Page 1 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Subpart W— Petroleum and Natural Gas Systems This redline strikeout document represents the changes proposed to the subparts A and W regulatory text in the proposed action: Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule signed by the EPA Administrator Gina McCarthy on February 20, 2014
Subpart A: Section 98.6 is amended by revising the de finition of “Well completions” to read as follows: Well completions means the process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. Well completion also involves connecting the we ll bore to the reservoir, which may include treating the formation or installing tubing, packer (s), or lifting equipment, steps that do not significantly vent natural gas to the atmosphe re. This process may also include high-rate flowback of injected gas, water, oil, and proppant used to fracture or re - fracture and prop open new fractures in existing lower permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere. Subpart W—Petroleum and Natural Gas Systems is amended as follows: §98.230 Definition of the source category

. (a) This source category consists of the following industry segments: (1) Offshore petroleum and natural gas production . Offshore petroleum and natural gas production is any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore. In addition, offshore production includes secondary pl atform structures connected to the platformPage 2 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. structure via walkways, storage tanks associated with the platform structure and floating production and storage offloading equipment (FPSO). This source category does not include reporting of emissions from offshore drilling and exploration that is not conducted on production platforms. (2) Onshore petroleum and natural gas production . Onshore petroleum and natural gas production means all equipment on a single well-pad or associated with a single well-pad (including but not limited to compressors, generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and processing equipment, and portable non-self-propelled equipment , which includes well drilling and comple tion equipment, workover equipment, gravity separation equipment, auxiliary non

- transportation

- related maintenance and repair equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate). This equipment also includes associated storage or measurement vessels , and all enhanced oil recovery (EOR) operations using CO 2 or natural gas injection, and all petroleum an d natural gas production equipment located on islands, artificial islands, or structures connected by a causeway to land, an island, or an artificial island. Onshore petroleum and natural gas production also means all equipment on or associated with a single enhanced oil recovery (EOR) well pad using
CO 2 or natural gas injection. (3) Onshore natural gas processing . Natural gas processing means the separation of natural gas liquids (NGLs) or non-methane gases from produced natural gas, or the separation of NGLs into one or more component mixtures. Separation includes one or more of the following: forced extraction of natural gas liquids, sulf ur and carbon dioxide removal, fractionation of NGLs, or the capture of CO 2 separated from natural gas stream s. This segment also includes allPage 3 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. residue gas compression equipment owned or operated by the natural gas processing plant. This industry segment includes processing plants that fractionate gas liquids, and processing plants that do not fractionate gas liquids but have an annual average throughput of 25 MMscf per day or greater. (4) Onshore natural gas transmission compression . Onshore natural gas transmission compression means any stationary combination of compressors that move natural gas from production fields, natural gas processing plants , or other transmission compressors through transmission pipelines to natural gas distributi on pipelines, LNG storage facilities, or into underground storage. In addition, a transmission compressor station includes equipment for liquids separation, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compression that is part of onshore natural gas processing plants are included in the onshore natural gas processing segment and are excluded from this segment. (5) Underground natural gas storage . Underground natural gas storage means subsurface storage, including depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas); natural gas underground storage processes and operations (including compression, dehydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compression units located at the facility that inject and recover natural gas into and from the underground reservoirs. (6) Liquefied natural gas (LNG) storage . LNG storage means onshore LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture andPage 4 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. re-liquefy boil-off-gas, re-condensers, and vaporization units for re-gasification of the liquefied natural gas. (7) LNG import and export equipment . LNG import equipment means all onshore or offshore equipment that receives imported LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers re-gasified natural gas to a natural gas transmission or distribution system. LNG export equipment means all onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to any location, including locations in the United States. (8) Natural gas distribution . Natural gas distribution means the distribution pipelines and metering and regulating equipment at metering-regulating stations that are operated by a Local Distribution Company (LDC) within a single st ate that is regulated as a separate operating company by a public utility commis sion or that is operated as an independent municipally-owned distribution system. This segment also excludes customer meters and regulators, infrastructure, and pipelines (both interstate and intrastate) deli vering natural gas directly to major industrial users and farm taps upstream of the local distribution company inlet. (b) [Reserved] §98.231 Reporting threshold

. (a) You must report GHG emissions under this subpart if your facility contains petroleum and natural gas systems and the facility meets the requirements of §98.2( a)(2). Facilities must report emissions from the onshore petroleum and natural gas production industry segment only if emission sources specified in paragraph §98.232(c) emit 25,000 metric tons of CO 2 equivalent or more per year. Facilities must re port emissions from the natural gas distribution industry segmentPage 5 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. only if emission sources specified in paragraph §98.232(i) emit 25,000 metric tons of CO 2 equivalent or more per year. (b) For applying the threshold defined in §98. 2(a)(2), natural gas processing facilities must also include owned or operated residue gas compression equipment. §98.232 GHGs to report

. (a) You must report CO 2 , CH 4 , and N 2 O emissions from each industry segment specified in paragraph (b) through (i) of this section, CO 2 , CH 4 , and N 2 O emissions from each flare as specified in paragraph (b) through (i) of this section, and stationary and portable combustion emissions as applicable as specified in paragraph (k) of this section. (b) For offshore petroleum and natural gas production, report CO 2, CH 4, and N 2 O emissions from equipment leaks, vented emission, and flare emission source types as identified in the data collection and emissions estimation study conducted by BOEMRE in compliance with 30 CFR 250.302 through 304. Offshore platfo rms do not need to report portable emissions. (c) For an onshore petroleum and natura l gas production facility, report CO 2, CH 4 , and
N 2 O emissions from only the following source type s on a single well-pad or associated with a single well-pad: (1) Natural gas pneumatic device venting. (2) [Reserved] (3) Natural gas driven pneumatic pump venting. (4) Well venting for liquids unloading. (5) Gas well venting during well completions without hydraulic fracturing. (6) Gas well venting during well completions with hydraulic fracturing. (7) Gas well venting during well workov ers without hydraulic fracturing.Page 6 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (8) Gas well venting during well work overs with hydraulic fracturing. (9) Flare stack emissions. (10) Storage tanks vented emissions from produced hydrocarbons. (11) Reciprocating compressor rod packing venting. (12) Well testing venting and flaring. (13) Associated gas venting and flaring from produced hydrocarbons. (14) Dehydrator vents. (15) [Reserved] (16) EOR injection pump blowdown. (17) Acid gas removal vents. (18) EOR hydrocarbon liquids dissolved CO 2 . (19) Centrifugal compressor venting. (20) [Reserved] (21) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other equipment leak sources (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps). (22) You must use the methods in §98.233(z) and report under this subpart the emissions of CO 2 , CH 4 , and N 2 O from stationary or portable fuel combustion equipment that cannot move on roadways under its own power and drive train, and that is located at an onshore petroleum and natural gas production facility as defined in §98.238. Stationary or portable equipment are the following equipment, which are in tegral to the extraction, processing, or movement of oil or natural gas: well drilling and completion equi pment, workover equipment, natural gas dehydrators, natural gas compressors, electrical ge nerators, steam boilers, and process heaters.Page 7 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (d) For onshore natural gas processing, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Blowdown vent stacks. (4) Dehydrator vents. (5) Acid gas removal vents. (6) Flare stack emissions. (7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. (e) For onshore natural gas transm ission compression, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Transmission storage tanks. (4) Blowdown vent stacks. (5) Natural gas pneumatic device venting. (6) [Reserved] Flare stack emissions. (7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. (f) For underground natural gas storage, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor rod packing venting.Page 8 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (2) Centrifugal compressor venting. (3) Natural gas pneumatic device venting. (4) [Reserved] Flare stack emissions. (5) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. (g) For LNG storage, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Equipment leaks from valves; pump seals; connectors; vapor recovery compressors, and other equipment leak sources. (4) Flare stack emissions. (h) LNG import and export equipment, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Blowdown vent stacks. (4) Equipment leaks from valves, pump seals, connectors, vapor recovery compressors, and other equipment leak sources. (5) Flare stack emissions. (i) For natural gas distribution, report CO 2 , CH 4 , and N 2 O emissions from the following

sources: (1) Meters, regulators, and associated equipment at above grade transmission

- distribution transfer stations, including equipment Equipment leaks from connectors, block valves, controlPage 9 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. valves, pressure relief valves, orifice meters, regulators, and open

- ended lines at above grade transmission-distributi on transfer stations

. (2) Equipment leaks from vaults at below grade transmission-distribution transfer stations. (3) Meters, regulators, and associated equipment Equipment leaks at above grade metering-regulating station stations that are not above grade transmission-distribution transfer stations

. (4) Equipment leaks from vaults at below grade metering-regulating stations. (5) Pipeline Distribution main equipment leaks. (6) Service line Distribution services equipment leaks. (7) Report under subpart W of this part the emissions of CO 2 , CH 4 , and N 2 O emissions from stationary fuel combustion sources following the methods in §98.233(z)

. (j) [Reserved] (k) Report under subpart C of this part (Gener al Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary fuel combustion unit by following the requirements of subpart C ex cept for facilities under onshore petroleum and natural gas production and natural gas distribution. Onshore petroleum and natural gas production facilities must report stationary and portable combustion em issions as specified in paragraph (c) of this section. Natural gas distribution facilities must report stationary co mbustion emissions as specified in paragraph (i) of this section. (l) You must report under subpart PP of this part (Suppliers of Carbon Dioxide), CO 2 emissions captured and transferred off site by following the requirements of subpart PP. §98.233 Calculating GHG emissions

.Page 10 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. You must calculate and report the annual GHG emissions as prescribed in this section. For actual conditions, reporters must use averag e atmospheric conditions or typical operating conditions as applicable to the respectiv e monitoring methods in this section. (a) Natural gas pneumatic device venting . Calculate CH 4 and CO 2 volumetric emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices using Equation W-1 of this section. 

#   t

i t i t t i s 

### T GHG EF Count E * * *

, (Eq. W-1)

Where:

Mass t E s ,i = Annual total mass volumetric GHG emissions at standard conditions in metric tons CO 2 e standard cubic feet per year from a natural gas pneumatic device vent s, of type s “t ”, ” (continuous high bleed, continuous low bleed, intermittent bleed), for GHG i . Count t = Total number of natural gas pneumatic devices of type “t” (continuous high bleed, continuous low bleed, intermittent bleed) as determined in paragraph (a)(1 ), ) or (a)(2 ), and (a)(3 ) of this section. EF t = Population emission factors for natural gas pneumatic device venting vents (in standard cubic feet per hour per device) of each type “t” listed in Tables W1A, W-3, and W-4 of this subpart for onshore petroleum and natural gas production, onshore natural gas transmission compression, and underground natural gas storage facilities, respectively. GHG i = For onshore petroleum and na tural gas production facilities, concentration of GHG i , CH 4 , or CO 2 , in natural gas as defined in paragraph (u)(2)(i) of this section and for onshore natural gas transmission compression facilities, and underground natural gas storage , GHG i equals 0.975 for CH 4 and 1.1 × 10 − 2 for CO 2 facilities, concentration of GHG i , CH 4 or CO 2 , in produced natural gas or processed natural gas for each facility as specified in paragraphs (u)(2)(i), (iii), and (iv) of this section

. Conv i = Conversion from standard cubic feet to metric tons CO 2 e; 0.0004 79 for CH 4 , and 0.00005262 for CO 2 . T t

= Average estimated number of hours in the operating year the devices, of each type “ t , ”, were operational using engineering estimates based on best available data . Default is 8760 hours.Page 11 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (1) For all industry segments, determine “Count t ” for Equation W-1 of this subpart for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) by counting the devices, except as specified in paragraph (a)(2) of this section. The reported number of devices must represent the total number of devices for the reporting year. onshore petroleum and natural gas production , provide the total number of continuous high bleed, c ontinuous low bleed, or intermittent bleed natural gas pneumatic devices of each type as follows: (i) In the first calendar year, for the total number of each type , you may count the total of each type, or count any percentage number of each type plus an engineering estimate based on best available data of the number not counted. (ii) In the second consecutive year, for the total number of each type, you may count the total of each type, or count any percentage number of each type plus an engineering estim ate based on best available data of the number not counted. (iii) In the third consecutive calendar year, complete the count of all pneumatic devices, including any changes to equipment counted in prior years. (iv) For the calendar year immediately followi ng the third consecutive calendar year, and for calendar years thereafter, facilities must update the total count of pneumatic devices and adjust accordingly to reflect any modifications due to changes in equipment. (2) For onshore natural gas transmission compression and underground natural gas storage, all natural gas pneumatic devices must be counted in the first year and updated every calendar year

. For the onshore petroleum and natural gas production industry segment, you have the option in the first two consecutive calendar years to determine “Count t ” for Equation W-1 ofPage 12 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. this subpart for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) using engineer ing estimates based on best available data. (3) For all industry segments, determine the type of pneumatic device using engineering estimates based on best available information. (4) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (b) [Reserved] (c) Natural gas driven pneumatic pump venting

. (1) Calculate CH 4 and CO 2 volumetric emissions from natural gas driven pneumatic pump venting using Equation W-2 of this section. Natural gas driven pneumatic pumps covered in paragraph (e) of this section do not have to report emissions under this paragraph (c ) of this section. ).



### T GHG EF Count E i i s 

### * * *

, 

###  (Eq. W-2)

Where:

Mass i E s,i = Annual total mass volumetric GHG emissions at standard conditions in metric tons CO 2 e standard cubic feet per year from all natural gas driven pneumatic pump venting, for GHG i . Count = Total number of natural gas driven pneumatic pumps. EF = Population emissions factors for natural gas driven pneumatic pumps (in standard cubic feet per hour per pump venting ) listed in Table s W-1A of this subpart for onshore petroleum and natural gas production. GHG i = Concentration of GHG i , CH 4 , or CO 2 , in produced natural gas as defined in paragraph (u)(2)(i) of this section. Conv i = Conversion from standard cubic feet to metric tons CO 2 e ; 0.0004 79 for CH 4 , and 0.00005262 for CO 2 . T = Average estimated number of hours in the operating year the pumps were operational using engineering estimates based on best available data . Default is 8760 hours.Page 13 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (2) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (d) Acid gas removal (AGR) vents . For AGR vent s (including processes such as amine, membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for CO 2 only (not CH 4 ) vented directly to the atmosphere or emitted through a flare, engine (e.g., permeate from a membrane or de-adsorbed gas from a pressure swing adsorber used as fuel supplement), or sulfur recovery plant , using any of the calculation method ologie s described in this paragraph (d) of this section , as applicable. (1) Calculation Method ology 1 . If you operate and maintain a continuous emissions monitoring system ( CEMS ) that has both a CO 2 concentration monitor and volumetric flow rate monitor, you must calculate CO 2 emissions under this subpart by following the Tier 4 Calculation Method ology and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpar t C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may foll ow the manufacturer’s instructions or industry standard practice. If a CO 2 concentration monitor and volumetric flow rate monitor are not available, you may elect to install a CO 2 concentration monitor and a volumetric flow rate monitor that comply with all of the requirements specified for the Tier 4 Calculation Method ology in subpart C of this part (General Stationary Fuel Combustion Sources ). The calculation and reporting of CH 4 and N 2 O emissions is not required as part of the Tier 4 requirements for AGRs AGR units

. (2) Calculation Method ology 2 . If a CEMS is not available but a vent meter is installed, use the CO 2 composition and annual volume of vent gas to calculate emissions using Equation W-3 of this section.Page 14 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 2 , 2 * CO a CO E Vs Vol  E a,CO2 = V S * Vol CO2 (Eq. W-3)

Where:

E a,CO2 = Annual volumetric CO 2 emissions at actual conditions, in cubic feet per year. V S = Total annual volume of vent gas flowing out of the AGR unit in cubic feet per year at actual conditions as determined by flow meter using methods set forth in §98.234(b). Alternatively, you may follow the manufacturer’s instructions or industry standard prac tice for calibration of the vent meter. Vol CO2 = Volume Annual average volumetric fraction of CO 2 content in vent gas flowing out of the AGR unit as determined in paragraph (d)(6) of this section. (3) Calculation Method ology 3 . If a CEMS or a vent meter is not installed, you may use the inlet or outlet gas flow rate of the acid gas removal unit to calculate emissions for CO 2 using Equations W-4A or W-4B of this section. If inlet gas flow rate is known, use Equation W-4A. If outlet gas flow rate is known, use Equation W-4B.
     

    O O I in CO a Vol Vol Vol V E 1 2 , (Eq. W-4A)

     

    I O I out CO a Vol Vol Vol V E 1 2 , (Eq. W-4B)

Where:

E a, CO2 = Annual volumetric CO 2 emissions at actual conditions, in cubic feet per year. V in = Total annual volume of natural gas flow into the AGR unit in cubic feet per year at actual condition s as determined using methods specified in paragraph (d)(5) of this section. V out = Total annual volume of natural gas flow out of the AGR unit in cubic feet per year at actual condition s as determined using methods specified in paragraph (d)(5) of this section. Vol I = Volume Annual average volumetric fraction of CO 2 content in natural gas flowing into the AGR unit as determined in paragraph (d)(7) of this section.Page 15 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Vol o = Volume Annual average volumetric fraction of CO 2 content in natural gas flowing out of the AGR unit as determined in paragraph (d)(8) of this section. (4) Calculation Method ology 4 . If CEMS or a vent meter is not installed, you may calculate emissions using any standard simulation software package s , such as AspenTech
HYSYS ® and , or API 4679 AMINECalc, that uses the Peng-Robinson equation of state , and speciates CO 2 emissions. A minimum of the following , determined for typical operating conditions over the calendar year by engineer ing estimate and process knowledge based on best available data , must be used to characterize emissions: (i) Natural gas feed temperature, pressure, and flow rate. (ii) Acid gas content of feed natural gas. (iii) Acid gas content of outlet natural gas. (iv) Unit operating hours, excluding downtime for maintenance or standby. (v) Exit temperature of natural gas. (vi) Solvent pressure, temperature, circulation rate, and weight. (5) Record For Calculation Method 3, determine the gas flow rate of the inlet and when using Equation W-4A of this section or the gas flow rate of the outletwhen using Equation W4B of this section for the natural gas stream of an AGR unit using a meter according to methods set forth in §98.234(b). If you do not have a continuous flow meter, either install a continuous flow meter or use an engineering cal culation to determine the flow rate. (6) If For Calculation Method 2, if a continuous gas analyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream to determine Vol CO2 in Equation W-3 of this section according to methods set forth in §98.234(b).Page 16 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (7) If For Calculation Method 3, if a continuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas stream to determine Vol I in Equation W-4A or W-4B of this section according to methods set forth in §98.234(b). (8) Determine volume For Calculation Method 3, determine annual average volumetric fraction of CO 2 content in natural gas flowing out of the AGR unit using one of the methods specified in paragraph s (d)(8 )(i) through (d)(8)(iii ) of this section. (i) If a continuous gas analyzer is installed on the outlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, you may install a continuous gas analyzer. (ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet gas stream to determine Vol O in Equation W-4A or W-4B of this section according to methods set forth in §98.234(b). (iii) Use If a continuous gas analyzer is not available or installed, you may use sales line quality specification for CO 2 in natural gas. (9) Calculate CO 2 annual volumetric CO 2 emissions at standard conditions using calculations in paragraph (t) of this section. (10) Calculate annual M m ass CO 2 emissions shall be calculated from volumetric CO 2

e missions at standard conditions using calculations in paragraph (v) of this section. (11) Determine if CO 2 emissions from the AGR unit are recovered and transferred outside the facility. Adjust the CO 2 emission s estimated in paragraphs (d)(1) through (d)(10) ofPage 17 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. this section downward by the magnitude of CO 2 emission s recovered and transferred outside the facility. (e) Dehydrator vents . For dehydrator vents, calculate annual CH 4 and CO 2 emissions using the applicable calculation methods described in paragraphs (e)(1) through (e)(4) of this section. If emissions from dehydrator vents ar e routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (e)(5) of this section. If emissions from dehydrator vents are routed to a flare or regene rator fire-box/fire tubes, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (e)(6) of this section.calculate annual
CH 4 , CO 2 and N 2 O emissions using any of the calculation m ethod ologie s described in paragraph (e) of this section. (1) Calculation Method ology 1 . Calculate annual mass emissions from dehydrator vents with absorbent dehydrators that have an annual average of daily natural gas throughput that is greater than or equal to 0.4 million standard cubic feet per day by using a software program, such as AspenTech HYSYS ® or GRI-GLYCalc TM , that uses the Peng-Robinson equation of state to calculate the equilibrium coefficient, speciates CH 4 and CO 2 emissions from dehydrators, and has provisions to include regenerator control devices, a separator flash tank, stripping gas and a gas injection pump or gas assist pump. A minimum of the The following parameters must be determined by engineering estimate based on best available data and must be used at a minimum to characterize emissions from dehydrators: (i) Feed natural gas flow rate. (ii) Feed natural gas water content. (iii) Outlet natural gas water content. (iv) Absorbent circulation pump type ( e.g., natural gas pneumatic/ai r pneumatic/electric).Page 18 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (v) Absorbent circulation rate. (vi) Absorbent type : including (e.g., triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG)

. ). (vii) Use of stripping gas. (viii) Use of flash tank separator (and disposition of recovered gas). (ix) Hours operated. (x) Wet natural gas temperature and pressure. (xi) Wet natural gas compositi on. Determine this parameter by selecting using one of the methods described under in paragraph s (e)(1)(xi )(A) through (e)(1)(xi)(D ) of this section. (A) Use the wet natural gas composition GHG mole fraction as defined in paragraph (u)(2)(i) or (u)(2)(ii) of this section. (B) If wet natural gas composition the GHG mole fraction cannot be determined using paragraph (u)(2)(i) or (u)(2)(ii) of this section, select a representative analysis. (C) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in §98.234(b) to sample and analyze wet natural gas composition. (D) If only composition data for dry natural gas is available, assume the wet natural gas is saturated. (2) Calculation Method ology 2 . Calculate annual CH 4 and CO 2 volumetric emissions from glycol dehydrators with that have an annual average of daily natural gas throughput that is less than 0.4 million standard cubic feet per day using Equation W-5 of this section:



### 1000 * *

, 

### Count EF E i i s 

###  (Eq. W-5)Page 19 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Where:

E s,i = Annual total volumetric GHG emissions (either CO 2 or CH 4 ) at standard conditions in cubic feet. EF i = Population emission factors for glycol dehydrators in thousand standard cubic feet per dehydrator per year. Use 73.4 for CH 4 and CH 4 and 3.21 for CO 2 at 60 °F and 14.7 psia. Count = Total number of glycol dehydrators with that have an annual average of daily natural gas throughput that is less than 0.4 million standard cubic feet per day. 1000 = Conversion of EF i in thousand standard cubic feet to standard cubic feet. (3) Determine if dehydrator unit has vapor reco very. Adjust the emissions estimated in paragraphs (e)(1 ) or (e)(2) of this section downward by the magnitude of emissions captured

. ( 4 ) Calculate annual emissions from dehydrat or vents to flares or regenerator fire

- box/fire tubes as follows: (A) Use the dehydrator vent volume and gas composition as determined in p aragraphs (e)(1) and (e)(2) of this section

. (B) Use the calculation method ology of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas vent. (5) Dehydrators that use desiccant shall calculate emissions from the amount of gas vented from the vessel when it is depressurized for the desiccant refilling process using Equation
W

- 6 of this section. Desiccant dehydrators covered in (e)(5) of this section do not have to report emissions under (i) of this section. Calculation Method 3. Dehydrators that use desiccant must calculate emissions from the amount of gas vented from the vessel when it is depressurized for the desiccant refilling process using Equation W-6 of this section. Desiccant dehydrator emissions covered in this paragraph do not have to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.Page 20 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 

#   ) 100 * * 4 ( * % * * * *

1 2 2

, P N G P p D H E n

s  (Eq. W-6) Where: E s,n = Annual natural gas emissions at standard conditions in cubic feet. H = Height of the dehydrator vessel (ft). D = Inside diameter of the vessel (ft). P 1 = Atmospheric pressure (psia). P 2 = Pressure of the gas (psia). P p = pi (3.14). %G = Percent of packed vessel volume that is gas. N = Number of dehydrator openings in the calendar year. 100 = Conversion of %G to fraction. ( 6 4 ) For glycol dehydrators, both CH 4 and CO 2 mass emissions shall be calculated from volumetric GHG i emissions using calculations in paragraph (v) of this section. For dehydrators that use desiccant, both CH 4 and CO 2 volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. For glycol dehydrators that use the calculation method in paragraph (e)(2) of this section, calculate both CH 4 and CO 2 mass emissions from volumetric GHG i emissions using calculations in paragraph (v) of this section. For desiccant dehydrators that use the calculation method in paragraph (e)(3) of this section, calculate both CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (5) Determine if the dehydrator unit has vapor recovery. Adjust the emissions estimated in paragraphs (e)(1), (e)(2), and (e)(3) of this section downward by the magnitude of emissionsPage 21 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. recovered using a vapor recovery system as determined by engineering estimate based on best available data. (6) Calculate annual emissions from dehydrator vents to flares or regenerator fire-box/fire tubes as follows: (i) Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(1) or (e)(2) of this section for absorbent dehy drators. Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(3) and (e)(4) of this section for dehydrators that use desiccant. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas vent. (f) Well venting for liquids unloadings . Calculate CO 2 and CH 4 annual volumetric natural
gas emissions from well venting for liquids unloading using one of the calculation method ologie s described in paragraphs (f)(1), (f)(2) , or (f)(3) of this section. Calculate annual
CH 4 and CO 2 volumetric and mass emissions using the method described in paragraph (f)(4) of this section. (1) Calculation Methodology 1

. Method 1 . Calculate emissions from wells with plunger lifts and wells without plunger lifts separately. For at least one well of each unique well tubing diameter group and pressure group combination in each sub-basin category (see §98.238 for the definitions of tubing diameter gr oup, pressure group, and sub-basin category), where gas wells are vented to the atmosphere to expel liquids accumulated in the tubing, install a recording flow

meter shall be installed on the vent line used to vent gas from the well (e.g., on the vent line off the wellhead separator or atmospheric storag e tank) according to methods set forth in §98.234(b). Calculate the total emissions from well venting to the atmosphere for liquidsPage 22 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. unloading using Equation W-7 A of this section . For any tubing diameter group and pressure group combination in a sub-basin where liquids unloading occurs both with and without plunger lifts, Equation W-7A will be used twice, once for wells with plunger lifts and once for wells without plunger lifts

. 

## 

  h

p p a T FR E 1 (Eq. W-7 A )

Where:

E a ,n = Annual natural gas emissions for all wells of the same tubing diameter group and pressure group combination in a sub-basin at actual conditions in cubic feet , a, in cubic feet. Calculate emissi on from wells with plunger lifts and wells without plunger lifts separately

. h = Total number of wells of the same tubing diameter group and pressure group combination in a sub-basin either with or without plunger lifts

. p = Wells 1 through h of the same tubing diameter group and pressure group combination in a sub-basin. T p = Cumulative amount of time in hours of venting for each well, p, of the same tubing diameter group and pressure group combination in a sub-basin during the year . If the available venting data do not contain a record of the date of the venting events and data are not available to provide the venting hours for the specific time period of January 1 to December 31, you may calculate an annualized vent time, T p , using Equation W-7B of this section

. FR = Average flow rate in cubic feet per hour for all measured wells venting for ofthe same tubing diameter group and pressure group combination in a subbasin, over the duration of the liquids unloading, under actual conditions as determined in paragraph (f)(1)(i) of this section.

x p p p p HR T D MP  (Eq. W-7B)

Where:

HR p = Cumulative amount of time in hours of venting for each well, p, during the monitoring period.Page 23 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. MP p = Time period, in days, of the monitoring period for each well, p. A minimum of 300 days in a calendar year are required. The next period of data collection must start immediately following the en d of data collectio n for the previous reporting year. D p = Time period, in days during which the well, p, was in production (365 if the well was in production for the entire year). (i) Determine the well vent average flow rate (“FR” in Equation W-7A of this section) as specified under paragraph in paragraphs (f)(1)(i )(A) through (f)(1)(i)(C ) of this section for at leastone well in a unique well tubing diameter group and pressure group combination in each subbasin category. Calculate emissions from wells with plunger lifts and wells without plunger lifts separately. (A) The Calculate the average flow rate per hour of venting is calc ulated for each unique tubing diameter group and pressure group combin ation in each sub-basin category by dividing the recorded total annual flow by the recorded time (in hours) for all measured liquid unloading events with venting to the atmosphere. (B) T his Apply the average hourly flow rate per hour is applied calculated under paragraph (f)(1)(i)(A) of this section to all wells in the same pressure group that have the same tubing diameter group, for the number of hours of venting these wells. (C) A Calculate a new average flow rate is calculated every other calendar year for each reporting sub

- basin category starting with the first calendar year of data collection. For a new producing sub-basin category, calculate an average flow rate is calculated beginning in the first year of production. (ii) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.Page 24 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (2) Calculation Method ology 2 . Calculate the total emissions for each sub-basin from well venting to the atmosphere for liquids unloading without plunger lift assist using Equation W-8 of this section. 

#          

         
         W

p V

q q p q p p p p p p s p Z HR SFR SP WD CD V E 1 1 , , 2 3 0

. 1 10 37

. 0 (Eq. W-8)

Where:

E s ,n = Annual natural gas emissions for each sub-basin at standard conditions, s, in cubic feet / per year.W = Total number of wells with well venting for liquids unloading for each subbasin.p = Wells 1 through W with well venting for liquids unloading for each subbasin. V p = Total number of unloading events in the monitoring period per well, p. 0.37×10 − 3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). CD p = Casing internal diameter for each well, p, in inches. WD p = Well depth from either the top of the well or the lowest packer to the bottom of the well, for each well, p, in feet. SP p = For each well, p, shut-in pressure or surface pressure for wells with tubing production , or casing pressure for each well with no packers , in pounds per square inch absolute (psia) ; or casing

- to

- tubing pressure ratio of one well with no packer from the same sub

- basin multiplied by the tubing pressure of each well , p, in the sub

- basin, in pounds per square inch absolute (psia)

. If casing pressure is not available for each well, you may determine the casing pressure by multiplying the tubing pressure of each well with a ratio of casing pressure to tubing pressure from a well in the same sub-basin for which the casing pressure is known. The tubing pressure must be measured during gas flow to a flow-line. The shut-in pressu re, surface pressure, or casing pressure must be determined just prior to liquids unloading when the well production is impeded by liquids loading or closed to the flow-line by surface valves.

V p = Number of unloading events per year per well, p

.Page 25 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. SFR p = Average flow-line rate of gas for well, p, at standard conditions in cubic feet per hour. Use Equation W-33 of this section to calculate the average flowline rate at standard conditions. HR p,q

= Hours that each well, p, was left open to the atmosphere during each unloading event, q. 1.0 = Hours for average well to blowdown casing volume at shut-in pressure. q = Unloading event. Z p,q = If HR p,q

is less than 1.0 then Z p,q is equal to 0. If HR p,q

is greater than or equal to 1.0 then Z p,q is equal to 1. (3) Calculation Method ology 3 . Calculate the total emissions for each sub-basin from well venting to the atmosphere for liquids unlo ading with plunger lift assist using Equation W-9 of this section. 

#          

         
         W

p V

q q p q p p p p p p s p Z HR SFR SP WD TD V E 1 1 , , 2 3 5

. 0 10 37

. 0 (Eq. W-9)

Where:

E s ,n = Annual natural gas emissions for each sub-basin at standard conditions, s, in cubic feet / per year. W = Total number of wells with plunger lift assist and well venting for liquids unloading for each sub-basin.p = Wells 1 through W with well venting for liquids unloading for each subbasin. V p = Total number of unloading events in the monitoring period for each well, p. 0.37×10 − 3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). TD p = Tubing internal diameter for each well, p, in inches. WD p = Tubing depth to plunger bumper for each well, p, in feet. SP p = Flow-line pressure for each well, p, in pounds per square inch absolute (psia), using engineering estimate based on best available data. V p = Number of unloading events per year for each well, p.Page 26 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. SFR p = Average flow-line rate of gas for well, p, at standard conditions in cubic feet per hour. Use Equation W-33 of this section to calculate the average flowline rate at standard conditions. HR p,q

= Hours that each well, p, was left open to the atmosphere during each unloading event, q. 0.5 = Hours for average well to blowdown tubing volume at flow-line pressure. q = Unloading event. Z p,q = If HR p,q

is less than 0.5 then Z p,q is equal to 0. If HR p,q

is greater than or equal to 0.5 then Z p,q is equal to 1. (i)

- (ii) [Reserved] (4) Both Calculate CH 4 and CO 2 volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (g) Gas well venting during completions and workovers from with hydraulic fracturing

. Calculate CH 4 , CO 2 and N 2 O annual emissions from gas well venting during completions involving hydraulic fracturing in wells and well workovers using Equation W

- 10A or Equation
W

- 10B of this section. Equation W

- 10A applies to well venting when the backflow rate is measured or calculated, Equation W

- 10B applies when the backflow vent or flare volume is measured . Use Equation W

- 10A if the flow rate for backflow during well completions and workovers from hydraulic fracturing is known for the specified number of wells per paragraph (g)(1) in a sub

- basin and well type (horizontal or vertical) combination. Use Equation W

- 10B if the flow volume for backfl ow during well completions and workovers from hydraulic fracturing is known for all wells in a sub

- basin and well type (horizontal or vertical) combination . Both
CH 4 and CO 2 volumetric and mass emissions shall be calculated from volumetric total gas emissi ons using calculations in paragraphs (u) and (v) of this section. Calculate annual volumetric natural gas emissions from gas well venting during completions and workovers involving hydraulic fracturing using Equation W-10A or Equation W-10B of this section.Page 27 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Equation W-10A applies to well venting when the flowback rate is measured from a specified number of example completions or workovers and Equation W-10B applies when the flowback vent or flare volume is measured for each completion or workover. Completion and workover activities are separated into two periods, an initial pe riod when flowback is ro uted to open pits or tanks and a subsequent period when gas content is sufficient to route the flowback to a separator or when the gas content is sufficient to allow measurement by the devices specified in paragraph (g)(1) of this section, regardless of whether a separator is actually utilized. If you elect to use Equation W-10A of this section, you must follow the procedures specified in paragraph (g)(1) of this section. Emissions must be calculated separately for completions and workovers, for each sub-basin, and for each well type combination iden tified in paragraph (g)(2) of this section. You must calculate CH 4 and CO 2 volumetric and mass emissions as specified in paragraph (g)(3) of this section. If emissions from gas well venting during completions and workovers with hydraulic fracturing are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (g)(4) of this section. 

#     

    

    W

p p s i i p p s p s s s p n s PR FRM T EnF PR FRM T E 1 , , , , , , 2 (Eq. W-10A) 

#     

   

  W

p i p i p p s p s n s FR T EnF FV E 1 , , , , , 2 (Eq. W-10B)

Where:

E s,n = Annual volumetric total natural gas emissions in standard cubic feet at standard conditions from gas well venting during completions or workovers following hydraulic fracturing for each sub-basin and well type (horizontal vs. vertical) combination. W = Total number of wells completed or worked over using hydraulic fracturing in a sub-basin and well type (horizontal vs. vertical) combination. Comment [EPA1]: Proposed Revised Equation.

Comment [EPA2]: Proposed Revised Equation.Page 28 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. T p ,s = Cumulative amount of time of backflow flowback, after sufficient quantities of gas are present to enable separation, where gas vented or flared for the completion or workover, in hours, for each well, p, in a sub-basin and well type (horizontal vs. vertical) combination during the reporting year. This may include non-contiguous periods of venting or flaring. T p,i = Cumulative amount of time of flowback to open tanks/pits, from when gas is first detected until sufficient quantities of gas are present to enable separation, for the completion or workover, in hours, for each well, p, in a sub-basin and well type combination during the reporting year. This may include non-contiguous periods of routing to open tanks/pits. FRM s = Ratio of average flowback , during the period when sufficient quantities of gas are present to enable separation, of well completions and workovers from hydraulic fracturing to 30-day production rate from Equation W

- 12. for the sub-basin and well type combination, calculated using procedures specified in paragraph (g)(1)(iii) of this section, expressed in standard cubic feet per hour. PR s,p = First 30

- day average production flow rate in standard cubic feet per hour of each well p, as requi red in paragraph (g)(1 ) of this section. FRM i = Ratio of initial flowback rate during well completions and workovers from hydraulic fracturing to 30-day production rate for the sub-basin and well type combination, calculated using procedures specified in paragraph (g)(1)(iv) of this section, expressed in standard cubic feet per hour, for the period of flow to open tanks/pits. PR s,p = Average production flow rate during the first 30 days of production after completions of newly drilled gas wells or gas well workovers using hydraulic fracturing in standard cubic feet per hour of each well p, that was measured in the sub-basin and well type combination. EnF s,p = Volume of CO 2 or N 2 injected gas in cubic feet at standard conditions that was injected into the reservoir during an energized fracture job for each well , p , as determined by using an appropriate meter according to methods described in § 98.234(b), or by using receipts of gas purchases that are used for the energized fracture job. Convert to standard conditions using paragraph (t) of this section . If the fracture process did not inject gas into the reservoir , then EnF s,p is 0. If or if the injected gas is CO 2 then EnF s,p is 0. SG s,p = Volume of natural gas in cubic feet at standard conditions that was recovered into a flow

- line for well p as per paragraph (g)(3) of this section. This parameter includes any natural gas that is injected into the well for clean

- up. If no gas was recovered, SG s,p is 0. FV s,p = Flow volume vented or flared of each well ( , p ) , in standard cubic feet measured using a recording flow meter (digital or analog) on the vent line toPage 29 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. measure flowback during the separation period of the completion or workover according to methods set forth in §98.234(b). FR p,i = Flow rate vented or flared of each well, p, in standard cubic feet measured using a recording flow meter (digital or analog) on the vent line to measure the flowback, at the beginning of the pe riod of time when sufficient quantities of gas are present to enable separation, of the completion or workover according to methods set forth in §98.234(b). (1) The average flow rate for flowback during well completions and workovers from hydraulic fracturing shall be determined using measurement(s) for Calculation Methodology 1 or calculation(s) for Calculation Methodology 2 described in this paragraph (g)(1) of this section. If Equation W

- 10A is used, the number of measurements or calculations shall be determ ined per sub

- basin and well type (horizontal or vertical) as follows: at least one measurement or calculation for less than or equal to 25 completions or workovers ; at least two measurements or calculations for 26 to 50 completions or workovers ; at least t hree measurements or calculations for 51 to 100 completions or workovers ; at least four measurements or calculations for 101 to 250 completions or workovers ; and at least five measurements or calculations for greater than 250 completions or workovers. If you elect to use Equation W-10A of this section, you must use Calculation Method 1 as specified in paragraph (g)( 1)(i) of this section, or Calculation Method 2 as specified in paragraph (g)(1)(ii) of this section, to determine the value of FRM s and FRM i . These values must be based on the flow rate for flowback, once sufficient gas is present to enable separation. The number of measurements or calculations required to estimate FRM s and FRM i must be determined individually for completions and workovers per sub-basin and well type as follows: complete measurements or calculations for a least one completion or workover for less than or equal to 25 completions or workovers for each well type within a sub-basin; complete measurements or calculations for at least two co mpletions or workovers for 26 to 50 completionsPage 30 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. or workovers for each sub-basin and well type combination; complete measurements or calculations for at least three completions or workovers for 51 to 100 completions or workovers for each sub-basin and well type combination; complete measurements or calculations for at least four completions or workovers for 101 to 250 completions or workovers for each sub-basin and well type combination; and complete measurements or calculations for at least five completions or workovers for greater than 250 completions or workovers for each sub-basin and well type combination. (i) Calculation Method ology 1

. When using Equation W

- 10A, for each measured well completion(s) in each gas producing sub

- basin category and well type (horizontal or vertical) combination and for each measured well workover(s) in each gas producing sub

- basin category and well type (horizontal or vertical) combinati on, a recording flow meter (digital or analog) shall be installed on the vent line, a head of a flare or vent if used , to measure the backflow rate according to methods set forth in §98.234(b). You must use Equation W-12A as specified in paragraph (g)(1)(iii) of this section to determine the value of FRM s . You must use Equation W12B as specified in paragraph (g)(1)(iv) of this section to determine the value of FRM i . The procedures specified in paragraphs (g)(1)(v) and (g)(1)(vi) also apply. When making flowback measurements for use in Equations W-12A and W-12B of this section, you must use a recording flow meter (digital or analog) installed on the ve nt line, ahead of a flare or vent, to measure the flowback rates in units of standard cubic feet per hour according to methods set forth in § 98.234(b). (ii) Calculation Method ology 2

. When using Equation W

- 10A, for each calculated horizontal well completion and each calculated vertical well completion in each gas producing sub

- basin category and for each calculated well horizontal workover and for each calculatedPage 31 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. vertical well workover in each ga s producing sub

- basin category, record the well flowing pressure upstream (and downstream in subsonic flow) of a well choke according to methods set forth in §98.234(b) to calculate the well backflow during well completions and workovers from hydraulic fra cturing. Calculate emissions using Equation W

- 11A of this section for subsonic flow or Equation W

- 11B of this section for sonic flow. Use best engineering estimate based on best available data along with Equation W

- 11C of this section to determine whether the predominant flow is sonic or subsonic. If the value of R in Equation W

- 11C is greater than or equal to 2, then flow is sonic; otherwise, flow is subsonic : You must use Equation W-12A as specified in paragraph (g)(1 )(iii) of this section to determine the value of FRM s . You must use Equation W-12B as specified in paragraph (g)(1)(iv) of this section to determine the value of
FRM i . The procedures specified in paragraphs (g)(1)(v) and (g)(1)(vi) also apply. When calculating the flowback rates for use in Equations W-12A and W-12B of this section based on well parameters, you must record the well flowing pressure immediately upstream (and immediately downstream in subsonic flow) of a well choke according to methods set forth in § 98.234(b) to calculate the well flowback. The upstream pressure must be surface pressure and reservoir pressure cannot be assumed. The downstream pressure must be measured after thechoke and atmospheric pressure cannot be assumed. Calculate flowback rate using Equation W11A of this section for subsonic flow or Equation W-11B of this section for sonic flow. You must use best engineering estimates based on best available data along with Equation W-11C of this section to determine whether the predominant flow is sonic or subsonic. If the value of R in Equation W-11C of this section is greater than or eq ual to 2, then flow is sonic; otherwise, flow is subsonic. Convert calculated FR a values shall be converted from actual conditions upstream ofPage 32 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. the restriction orifice to standard conditions (FR s,p and FR i,p ) for use in Equations W-12A and W12B of this section using Equation W-33 in paragraph (t) of this section.

               

           758

. 1

1 2 515

. 1

1 2 5 * * 3430 * * 10 27

. 1 P P P P T A FR u a (Eq. W-11A)

Where:

FR a = Average flow Flowback rate in actual cubic feet per hour, under actual subsonic flow conditions. A = Cross sectional open area of the restriction orifice (m 2 ). P 1 = Upstream pressure Pressure immediately upstream of the choke (psia). T u = Upstream temperature Temperature immediately upstream of the choke (degrees Kelvin). P 2 = Downstream pressure Pressure immediately downstream of the choke (psia). 3430 = Constant with units of m 2 /(sec 2 * K). 1.27*10 5 = Conversion from m 3 /second to ft 3 /hour.

u a T A FR * 08

. 187 * * 10 27

. 1 5   (Eq. W-11B)

Where:

FR a = Av erage flow Flowback rate in actual cubic feet per hour, under actual sonic flow conditions. A = Cross sectional open area of the restriction orifice (m 2 ). T u = Upstream temperature Temperature immediately upstream of the choke (degrees Kelvin). 187.08 = Constant with units of m 2 /(sec 2 * K). 1.27*10 5 = Conversion from m 3 /second to ft 3 /hour.

2 1 P P R  (Eq. W-11C)
Where:Page 33 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. R = Pressure ratio

. P 1 = Pressure immediately upstream of the restriction orifice in pounds per square inch absolute. choke (psia). P 2 = Pressure immediately downstream of the restriction orifice in pounds per square inch absolute. choke (psia). (iii) For Equation W-10A , the ratio of backflow rate during well completions and workovers from hydraulic fracturing to 30

- day produc tion rate is calculated of this section, calculate FRM s using Equation W-12 A of this section.



##  

   N

p p s N

p p s

s PR FR FRM

1 , 1 , (Eq. W-12 A )

Where:

FRM s = Ratio of average flowback rate during , during the period of time when sufficient quantities of gas are present to enable separation, of well completions and workovers from hydraulic fracturing to 30-day production rate for each sub-basin and well type combination

. FR s,p = Measured average flowback rate from Calculation Method ology 1 described in paragraph (g)(1)(i) of this section or calculated flow average flowback rate from Calculation Method ology 2 described in paragraph (g)(1)(ii) of this section , during the separation period in standard cubic feet per hour for well(s) p for each sub-basin and well type (horizontal or vertical) combination. Measured Convert measured and calculated FR a values shall be converted from actual conditions upstream of the restriction orifice (FR a ) to standard conditions (FR s,p ) for each well p using Equation W-33 in paragraph (t) of this section. You may not use flow volume as used in Equation W-10B converted to a flow rate for this parameter. PR s,p = First 30

- day Average production flow rate during the first 30 days of production rate after completions of newly drilled gas wells or gas well workovers using hydraulic fracturing, in standard cubic feet per hour for each well , p , that was measured in the sub-basin and well type combination. N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub-basin and well type combination.Page 34 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iv) For Equation W-10A of this section, calculate FRM i using Equation W-12B of this section.

, 1

, 1 N i p p i N

s p p FR FRM PR 

  

## 

 (Eq. W-12B)

Where:

FRM i = Ratio of flowback gas rate while flowing to open tanks/pits during well completions and workovers from hydraulic fracturing to 30-day production rate. FR i,p = Initial measured gas flowback rate fr om Calculation Method 1 described in paragraph (g)(1)(i) of this section or initial calculated flow rate from Calculation Method 2 described in paragraph (g)(1)(ii) of this section in standard cubic feet per hour for well(s), p, for each sub-basin and well type combination. Measured and calculated FR i,p values must be based on flow conditions at the beginning of the sepa ration period and must be expressed at standard conditions. PR s,p = Average production flow rate during the first 30-days of production after completions of newly drilled gas wells or gas well workovers using hydraulic fracturing, in standard cubic feet per hour of each well, p, that was measured in the sub-basin and well type combination. N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub-basin and well type combination. ( iv v ) For Equation W-10A of this section , the ratio of backflow flowback rate during well completions and workovers from hydraulic fracturing to 30-day production rate for horizontal and vertical wells are applied to all horizontal and vertical well completions in the gas producing sub-basin and well type combination and to all horizontal and vertical well workovers, respectively, in the gas producing sub-basin and well type combination for the total number of hours of backflow flowback and for the first 30 day average production rate for each of these wells.Page 35 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. ( v vi ) For Equation W- 10A, 12A and W-12B of this section, calculate new flow back rates for horizontal and vertical gas well completions and horizontal and vertical gas well workovers in each sub-basin category shall be calculated once every two years starting in the first calendar year of data collection. (2) The volum e of CO 2 or N 2 injected into the well reservoir during energized hydraulic fractures will be measured using an appropriate meter as described in 98.234(b) or using receipts of gas purchases that are used for the energized fracture job. For paragraphs (g) introductory text and (g)(1) of this section, measurements and calculations are completed separately for workovers and completions per sub-basin and well type combination. A well type combination is a unique combination of the parameters listed in paragraphs (g)(2)(i) through (g)(2)(iii) of this section. (i) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section. (i) Vertical or horizontal (directional drilling). (ii) [Reserved] With flaring or without flaring. (iii) Reduced emission completion/workover or not reduced emission completion/workover. (3) Determine if the backflow gas from the well completion or workover from hydraulic fracturing is recovered with purpose designed equipment that separates natural gas from the backflow, and sends this natural gas to a flow

- line ( e.g., reduced emissions completion or workovers). (i) Use the factor SG s,P in Equation W

- 10A of this section, to adjust the emissions estimated in paragraphs (g)(1) through (g)(4) of this section by t he magnitude of emissionsPage 36 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. captured using purpose designed equipment that separates saleable gas from the flowback as determined by engineering estimate based on best available data. (iii) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section. (4) Calculate B b oth CH 4 and CO 2 volumetric and mass emissions shall be calculated from total natural gas volumetric total emissions using calculations in paragraphs (u) and (v) of this section. ( 5 4 ) Calculate annual emissions from gas well venting during well completions and workovers from hydraulic fracturing to flares as follows: where all or a portion of the gas is flared as specified in paragraphs (g)(4)(i) and (g)(4)(ii) of this section. (i) Use the volumetric total gas w ell venting volume natural gas emissions vented to the atmosphere during well completions and workovers as determined in paragraph (g) of this section to calculate volumetric and mass emissions us ing paragraphs (u) and (v) of this section

. (ii) Use the calculation method ology of flare stacks in paragraph (n) of this section to determine adjust emissions for the portion of gas well venting flared during well completions and workovers using hydraulic fracturing emissions from the flare . This adjustment to emissions from completions using flaring , versus completions without flaring , accounts for the conversion of CH 4 to CO 2 in the flare and for the formation on N 2 O during flaring

. (h) Gas well venting during completions and workovers without hydraulic fracturing

. Calculate CH 4 , CO 2 and N 2 O annual volumetric natural gas emissions from each gas well venting during well completions and workovers not involving without hydraulic fracturing using Equation W-13 A of this section : . Calculate annual volumetric natural gas emissions from each gas well venting during completions without hydraulic fracturing using Equation W-13B of thisPage 37 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. section. You must convert annual volumetric natural gas emissions to CH 4 and CO 2 volumetric and mass emissions as specified in paragraph (h )(1) of this section. If emissions from gas well venting during completions and workovers without hydraulic fracturing are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (h)(2) of this section.

wo wo wo s 

### EF N E *

, 

###  (Eq. W-13 A)

p f

p p p s T V E * 1 , 

## 

  (Eq. W-13B )

Where:

E s, n wo = Annual volumetric natural gas emissions in standard cubic feet from gas well venting during well completions and workovers without hydraulic fracturing. N wo = Number of workovers per sub-basin category that flare gas or vent gas to the atmosphere and do not involve hydraulic fracturing in the reporting year. EF wo = Emission F f actor for non-hydraulic fracture well workover venting in standard cubic feet per workover. EF wo = Use 3 , 114 standard cubic feet natural gas per well workover without hydraulic fracturing. E s,p = Annual volumetric natural gas emissions in standard cubic feet from gas well venting during well completions without hydraulic fracturing. p = Well completions 1 through f in a sub-basin. f = Total number of well completions with out hydraulic fracturing in a sub-basin category. V p = Average daily gas production rate in standard cubic feet per hour for each well , p, undergoing completion without hydraulic fracturing , p . This is the total annual gas production volume divided by total number of hours the wells produced to the flow-line. For completed wells that have not established a production rate, you may use the average flow rate from the first 30 days of production. In the event that the well is completed less than 30 days from the end of the calendar year, the first 30 days of the production straddling the current and following calendar years shall be used. Comment [EPA3]: Proposed Revised Equation.

Comment [EPA4]: Proposed New Equation.Page 38 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. T p = Time that gas is vented to either the atmosphere or a flare for each well , p, undergoing completion without hydraulic fracturing, p, was venting in hours during the year. (1) Volumetric emissions for Calculate both CH 4 and CO 2 shall be calculated volumetric emissions from volumetric natural gas volumetric emissions using calculations in paragraph (u) of this section. Mass emissions for Calculate both CH 4 and CO 2 shall be calculated mass emissions from volumetric natural gas emissions vented to atmosphere using calculations in paragraph s (v) of this section. (2) Calculate annual emissions of CH 4 , CO 2 , and N 2 O from gas well venting to flares during well completions and workovers not involving hydraulic fracturing to flares as follows: as specified in paragraphs (h)(2)(i) and (h)(2)(ii) of this section. (i) Use the gas well venting volume and gas composition during well completions and workovers that are flared as determined using the methods specified in paragraph s (h) and (h)(1) of this section. (ii) Use the calculation method ology of flare stacks in paragraph (n) of this section to determine emissions from the flare for gas well venting to a flare during well completions and workovers emissions without hydraulic fracturing from the flare

. (i) Blowdown vent stacks . Calculate CO 2 and CH 4 blowdown vent stack emissions from depressurizing the depressurization of equipment (s) to reduce system pressure for planned or emergency shutdowns resulting from human intervention or to take equipment out of service for maintenance (excluding as specified in either paragraph (i)(2) or (i)(3) of this section. Equipment with a unique physical volume of less than 50 cubi c feet as determined in paragraph (i)(1) of this section are not subject to the requirements in paragraphs (i)(2) through (i)(4) this section. The requirements in this paragraph (i) do not apply to blowdown vent stack emissions fromPage 39 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. depressurizing to a flare, over-pressure re lief, operating pressure control venting and , blowdown of non-GHG gases ; , and desiccant dehydrator blowdown venting before reloading is covered in paragraph (e)(5) of this section) as follows:

. (1) Calculate the Method for calculating unique physical volumes . You must calculate each unique physical volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, discharge bottles, an d vessels) between isolation valves determined , in cubic feet, by using engineering estimates based on best available data. (2) If the unique physical volume between isolation valves is grea ter than or equal to 50 cubic feet, retain logs of the number of blowdow ns for each unique physical volume (including but not limited to compressors, vessels, pipelines, headers, fractionators, and tanks). Unique physical volumes smaller than 50 cubic feet are exempt from reporting under paragraph (i) of this section. (3 ) Method for determining emissions from blowdown vent stacks according to equipment type . If you elect to determine emissions according to each equipment type, using unique physical volumes as calculated in paragraph (i)(1) of this section, you must calculate emissions as specified in paragraphs (i)(2)(i) thro ugh (i)(2)(iii) of this section for each equipment type. Equipment types must be grouped into th e following seven categories: station piping, pipeline venting, compressors, scrubbers/strainers, pig launchers and receivers, emergency shutdowns, and all other blowdowns greater than or equal to 50 cubic feet. (i) Calculate the total annual venting natural gas emissions for from each unique volumes physical volume that is blown down using either Equation W-14A or W-14B of this section.Page 40 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 

##     , 

### 459.67 * * 459.67 s a s n a sa 

### T P E N V VC T PZ     
           (Eq. W-14A)

Where:

E s,n = Annual natural gas venting emissions at standard conditions from blowdowns each unique physical volume that is blown down, in cubic feet. N = Number of occurrences of blowdowns for each unique physical volume in the calendar year. You must retain logs documenting the number of occurrences of blowdowns for each unique physical volume in the calendar year. V = Unique physical volume (including pipelines, compressors and vessels) between isolation valves , in cubic feet , as calculated in paragraph (i)(1) of this section

. C = Purge factor that is 1 if the unique physical volume is not purged , or zero 0 if the unique physical volume is purged using non-GHG gases. T s = Temperature at standard conditions (60 °F). T a

= Temperature at actual conditions in the unique physical volume (°F). P s = Absolute pressure at standard conditions (14.7 psia). P a = Absolute pressure at actual conditions in the unique physical volume (psia). Z a

= Compressibility factor at actual conditions for natural gas. You may use 1 if the temperature is above -10 degrees Fahrenheit and pressure is below 5 atmospheres, or if the compressibility factor at the actual temperature and pressure is 0.98 or greater. 

##   

#     ,, ,,

, 1 , 

### 459.67 459.67 N s ab p ae p p s n p ap s a 

### TP P E V T PZ

 

###                 

#  (Eq. W-14B)

Where:

E s,n = Annual natural gas venting emissions at standard conditions from blowdowns each unique physical volume that is blown down, in cubic feet. p = Individual occurrence of blowdown for the same unique physical volume. N = Number of occurrences of blowdowns for each unique physical volume in the calendar year. You must retain logs documenting the number of occurrences of blowdowns for each unique physical volume in the calendar year. Comment [EPA5]: Proposed Revised Equation.

Comment [EPA6]: Proposed Revised Equation.Page 41 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. V p = Total Unique physical volume (including pipelines, compressors and vessels) between isolation valves , in cubic feet , for each blowdown “p.” T s = Temperature at standard conditions (60 °F). T a,p = Temperature at actual conditions in the unique physical volume ( °F) for each blowdown “p”. P s = Absolute pressure at standard conditions (14.7 psia). P a,b,p = Absolute pressure at actual conditions in the unique physical volume (psia) at the beginning of the blowdown “p”. P a,e,p = Absolute pressure at actual conditions in the unique physical volume (psia) atthe end of the blowdown “p”; 0 if blowdown volume is purged using nonGHG gases. Z a

= Compressibility factor at actual conditions for natural gas. You may use 1 if the temperature is above -10 degrees Fahrenheit and pressure is below 5 atmospheres, or if the compressibility factor at the actual temperature and pressure is 0.98 or greater. (ii) Calculate the annual natural gas emissions, in cubic feet, from each equipment type by summing E s,n , as calculated in either Equation W-14A or Equation W-14B of this subpart, for all unique physical volumes associated with the equipment type. (iii) Calculate total annual CH 4 and CO 2 volumetric and mass emissions from each equipment type by using the annual natural gas emission value calculated in paragraph (i)(2)(ii) of this section for the equipment type and the calculation method specified in paragraph (i)(4) of this section. (3) Method for determining emissions from blowdown vent stacks using a flow meter . In lieu of determining emissions from blowdown vent stacks using unique physical volumes as specified in paragraphs (i)(1) and (i)(2) of this section, you may use a flow meter and measure blowdown vent stack emissions. If you choose to use this method, you must measure the natural gas emissions from the blowdown(s) at the faci lity using a flow meter according to methods inPage 42 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. §98.234(b), and calculate annual CH 4 and CO 2 volumetric and mass emissions measured by the meters according to paragraph (i)(4) of this section. (4) Method for converting from natural gas emissions to GHG volumetric and mass emissions

. Calculate both CH 4 and CO 2 volumetric and mass emissions using calculations the methods specified in paragraph s (u) and (v) of this section. (j) Onshore production storage tanks . Calculate CH 4 , CO 2 , and N 2 O (when flared) emissions from atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore petroleum and natural gas produ ction facilities (including stationary liquid storage not owned or operated by the reporter), calculate annual CH 4 and CO 2 e missions using any of the calculation methodologies described in this paragraph (j). as specified in this paragraph (j). For wells flowing to gas-liquid separators w ith annual average daily throughput of oil greater than or equal to 10 barrels per day, calculate annual CH 4 and CO 2 using Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (j)(2) of this section. For wells flowing directly to atmospheric storage tanks without passing thr ough a wellhead separator with throughput greater than 10 barrels per day, calculate annual CH 4 and CO 2 emissions using Calculation Method 2 as specified in paragraph (j)(2) of this section. For wells flowing to ga s-liquid separators or directly to atmospheric storage tanks with throughput less than 10 barrels per day, use Calculation Method 3 as specified in paragraphs (j)(3) of this section. You must also calculate emissions that may have occurred due to dump valves not closing properly using the method specified in paragraph (j)(6) of this section. If emissions from atmospheric pressure fixed roof storage tanks are routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (j)(4) of this section. If emissions fr om atmospheric pressure fixed roof storage tanksPage 43 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (j)(5) of this section. (1) Calculation Method ology 1

. For separators with annual average daily throughput of oil greater than or equal to 10 barrels per day. Calculate annual CH 4 and CO 2 emissions from onshore production storage tanks using operating conditions in the last wellhead gas-liquid separator before liquid transfer to storage tanks . Calculate flashing emissions with a software program, such as AspenTech HYSYS ® or API 4697 E&P Tank, that uses the Peng-Robinson equation of state, models flas hing emissions, and speciates CH 4 and CO 2 emissions that will result when the oil from the separator enters an atmospheric pressure storage tank. A minimum of the The following parameters must be determined for typical ope rating conditions over the year by engineering estimate and process knowledge based on best available data , and must be used at a minimum to characterize emissions from liquid transferred to tanks

. : (i) Separator temperature. (ii) Separator pressure. (iii) Sales oil or stabilized oil API gravity. (iv) Sales oil or stabilized oil production rate. (v) Ambient air temperature. (vi) Ambient air pressure. (vii) Separator oil composition and Reid vapor pressure. If th is data is not available, determine these parameters by u s elect ing one of the methods described under paragraph in paragraphs (j)(1 ) ( )( vii )(A) through (j)(1)(vii)(C ) of this section.Page 44 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (A) If separator oil composition and Reid vapor pressure default data are provided with the software program, select the default values that most closely match your separator pressure first, and API gravity secondarily. (B) If separator oil composition and Reid vapor pressure data are available through your previous analysis, select the latest available analysis that is representative of produced crude oil or condensate from the sub-basin category. (C) Analyze a representative sample of separator oil in each sub-basin category for oil composition and Reid vapor pressure using an appropriate standard method published by a consensus-based standards organization. (2) Calculation Method ology 2 . Calculate annual CH 4 and CO 2 emissions from onshore production storage tanks for wellhead gas

- liquid separa tors with annual average daily throughput of oil greater than or equal to 10 barrels per day by assuming that all of the CH 4 and CO 2 in solution at separator temperature and pressure is emitted from oil sent to storage tanks

. , using either of the methods in paragraphs (j)(2)(i) or (j)(2)(ii) of this section. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as described in §98.234(b) to sample and analyze separator oil composition at separator pressure and temperature. (3) Calculation Methodology 3

. For wells with annual average daily oil production greater than or equal to 10 barrels per day that fl ow directly to atmospheric storage tanks without passing through a wellhead separator, calculate a nnual CH 4 and CO 2 e missions by either of the methods in paragraph (j)(3) of this section: (i) If well production oil and gas compositions are available through your previous analysis, select the latest available analysis that is representative of produced oil and gas from thePage 45 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. sub-basin category and assume all of the CH 4 and CO 2 in both oil and gas are emitted from the tank. (ii) If well production oil and gas compositions are not available, use default oil and gas compositions in software programs, such as API 4697 E&P Tank, that most closely match your well production gas/oil ratio and API gravity and assume all of the CH 4 and CO 2 in both oil and gas are emitted from the tank. ( 4 3 ) Calculation Methodology 4

. For wells with annual average daily oil productio n greater than or equal to 10 barrels per day that flow to a separator not at the well pad, calculate annual Method 3 . Calculate CH 4 and CO 2 emissions by either of the methods in paragraph (j)(4) of this section: (i) If well production oil and gas compositions are available through your previous analysis, select the latest available analysis that is representative of oil at separator pressure determined by best available data and assume all of the CH 4 and CO 2 in the oil is emitted from the tank. (ii) If well production oil composition is not avai lable, use default oil composition in software programs, such as API 4697 E&P Tank, that most closely match your well production API gravity and pressure in the off

- well pad separator determined by best availa ble data. Assume all of the CH 4 and CO 2 in the oil phase is emitted from the tank. (5) Calculation Methodology 5

. For well pad gas

- liquid separators and for wells flowing off a well pad without passing through a gas

- liquid separator with annual average dai ly throughput of oil less than 10 barrels per day use using Equation W-15 of this section:



### 1000 * *

, 

### Count EF E i i s 

###  (Eq. W-15)Page 46 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Where:

E s,i = Annual total volumetric GHG emissions (either CO 2 or CH 4 ) at standard conditions in cubic feet. EF i = Population emission factor for separators or wells in thousand standard cubic feet per separator or well per year, for crude oil use 4.2 for CH 4 and 2.8 for CO 2 at 60 °F and 14.7 psia, and for gas condensate use 17.6 for CH 4 and 2.8 for CO 2 at 60 °F and 14.7 psia. Count = Total number of separators or wells with annual average daily throughput less than 10 barrels per day. Count only separa tors or wells that feed oil directly to the storage tank. 1,000 = Conversion from thousand standard cubic feet to standard cubic feet. ( 6 4 ) Determine if the storage tank receiving your separator oil has a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (j)(1) through (j)( 5 3 ) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data. (ii) [Reserved] ( 57 ) Determine if the storage tank receiving y our separator oil is sent to flare(s). (i) Use your separator flash gas volume an d gas composition as determined in this section. (ii) Use the calculation method ology of flare stacks in paragraph (n) of this section to determine your contribution to storage tank emissions from the flare. ( 8 6 ) Calculate emissions from occurrences of well pad gas-liquid separator liquid dump valves not closing during the calendar year by using Equation W-16 of this section. 

###      

 n n n o i s 

### T E CF E * 8760 *

, , (Eq. W-16)Page 47 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Where:

E s,i ,o = Annual total volumetric GHG emissions at standard conditions from each storage tank in cubic feet that resulted from the dump valve on the gas-liquid separator not closing properly

. E n = Storage tank emissions as determined in Calculation Method ologie s 1, 2, or 4 3 in paragraphs (j)(1), (j)(2) , and (j)( 4 3 ) of this section (with wellhead separators) in standard cubic feet per year. T n = Total time the a dump valve is not closing properly in the calendar year in hours. Estimate T n is estimated by based on maintenance or , operations records (records) such that when a record shows the valve to be open improperly, it is assumed , or routine well pad inspections that indicate the period of time when the valve was malfunctioning in open or partially open position. for the entire time peri od preceding the record starting at either the beginning of the calendar year or the previous record showing it closed properly within the calendar year. If a subsequent record shows it is closing properly, then assume from that time forward the valve clos ed properly until either the next record of it not closing properly or, if there is no subsequent record, the end of the calendar year. CF n = Correction factor for tank emissions for time period T n is 3 2 .87 for crude oil production. Correction factor for tank emissions for time period T n is 5 4 .37 for gas condensate production. Correction factor for ta nk emissions for time period T n is 1.0 for periods when the dump valve is closed. 8,760 = Conversion to hourly emissions. ( 9 7 ) Calculate both CH 4 and CO 2 mass emissions from volumetric natural gas volumetric emissions using calculations in paragraph (v) of this section. (k) Transmission storage tanks . For vent stacks connected to one or more transmission condensate storage tanks, either water or hydrocarbon, without vapor recovery, in onshore natural gas transmission co mpression, calculate CH 4 , and CO 2 and N 2 O annual emissions from compressor scrubber dump valve leakage as follows: specified in paragraphs (k)(1) through (k)(3) of this section. If emissions from compressor sc rubber dump valve leakage are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (k)(4) of this section.Page 48 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (1) Except as specified in paragraph (k)(1)(iv) of this section, you must M m onitor the tank vapor vent stack annually for emissions using one of the methods specified in paragraphs (k)(1)(i) through (k)(1)(iii) of this section. (i) Use an optical gas imaging instrument according to methods set forth in § 98.234(a)(1 ) or by directly measuring ). (ii) Measure the tank vent directly using a flow meter or high volume sampler according to methods in § 98.234(b) through or (d) for a duration of 5 minutes , or
. (iii) Measure the tank vent using a calibrated bag according to methods in § 98.234( b). Or
you c) for a duration of 5 minutes or until the bag is full, whichever is shorter. (iv) You may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak detection device according to methods set forth in §98.234(a)(5). (2) If the tank vapors from the vent stack are continuous for 5 minutes, or the acoustic leak detection device detects a leak, then you must use one of the following two methods in either paragraph (k)(2 )(i) or (k)(2)(ii) of this section and th e requirements specified in paragraphs (k)(2)(iii) and (k)(2)(iv ) of this section to quantify annual emissions :
. (i) Use a flow meter, such as a turbine meter, calibrated bag, or high flow volume sampler to estimate tank vapor volumes from the vent stack according to methods set forth in §98.234(b) through (d). If you do not have a continuous flow measurement device, you may install a flow measuring device on the tank vapor vent stack. If the vent is directly measured for five minutes under paragraph § 98.233 (k)(1 )(ii) or (k)(1)(iii ) of this section to detect continuous leakage, this serves as the measurement. (ii) Use an acoustic leak detection device on each scrubber dump valve connected to the tank according to the method set forth in §98.234(a)(5).Page 49 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iii) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section. (iv) Calculate GHG CH 4 and CO 2 volumetric and mass emissions at standard conditions using calculations in paragraphs (t), (u), and (v) of this section, as applicable to the monitoring equipment used. (3) If the leaking dump valve (s) is fixed following leak detection , the annual emissions shall be calculate d from the beginning of the calendar year to the time the valve (s) is repaired. If a leaking dump valve is identified, the leak must be counted as having occurred since the beginning of the calendar year, or from the previous test that did not detect leaking in the same calendar year. If the leak ing dump valve is fixed following leak detection, the leak duration will end upon being repaired. If a leaking dump valve is identified and not repaired, the leak must be counted as having occurred through the rest of the calendar year. (4) Calculate annual emissions from storage tanks to flares as follows: specified in paragraphs (k)(4)(i) and (k)(4)(ii) of this section. (i) Use the storage tank emissions volume and gas composition as determined in paragraphs (k)(1) through (k)(3) of this section. (ii) Use the calculation method ology of flare stacks in paragraph (n) of this section to determine storage tank emissions sent to a flare. (l) Well testing venting and flaring . Calculate CH 4 , and CO 2 and N 2 O (when flared) annual emissions from well testing venting and flaring emissions as follows: specified in paragraphs (l)(1) through (l)(5) of this section. If emissions from well testing venting are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (l)(6) of this section.Page 50 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (1) Determine the gas to oil ratio (GOR) of the hydrocarbon production from oil well(s) tested. Determine the production rate from gas well(s) tested. (2) If GOR cannot be determined from your available data, then you must measure quantities reported in this section according to one of the two procedures specified in paragraph (l)(2 )(i) or (l)(2)(ii ) of this section to determine GOR :
. (i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists. (ii) Or you You may use an industry standard practice as described in §98.234(b). (3) Estimate venting emissions using Equation W-17A (for oil wells) or Equation W-17B (for gas wells) of this section.



### D FR GOR E n

a 

### * *

, 

###  (Eq. W-17A)



### D PR E n

a 

### *

, 

###  (Eq. W-17B)

Where:

E a,n = Annual volumetric natural gas emissi ons from well(s) testing in cubic feet under actual conditions. GOR = Gas to oil ratio in cubic feet of ga s per barrel of oil; oil here refers to hydrocarbon liquids produ ced of all API gravities. FR = Flow Average annual flow rate in barrels of oil per day for the oil well(s) being tested. PR = Average annual production rate in actual cubic feet per day for the gas well(s) being tested. D = Number of days during the calendar year , that the well(s) is tested. (4) Calculate natural gas volumetric emission s at standard conditions using calculations in paragraph (t) of this section.Page 51 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (5) Calculate both CH 4 and CO 2 volumetric and mass emissions from volumetric natural
gas volumetric emissions using calculations in paragraphs (u) and (v) of this section. (6) Calculate emissions from well testing to flares if emissions are routed to a flare as follows: specified in paragraphs (l)(6)(i) and (l)(6)(ii) of this section. (i) Use the well testing emissions volume and gas composition as determined in paragraphs (l)(1) through ( 3 4 ) of this section. (ii) Use the calculation method ology of flare stacks in paragraph (n) of this section to determine well testing emissions from the flare. (m) Associated gas venting and flaring . Calculate CH 4 , and CO 2 and N 2 O (when flared) annual emissions from associated gas venting and flaring emissions not in conjunction with well testing (refer to paragraph (l): Well testing venting and flaring of this section) as follows: specified in paragraphs (m)(1) through (m)(4) of this section. If emissions from associated gas venting are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (m)(5) of this section. (1) Determine the GOR of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, use the GOR from a cluster of wells in the same sub-basin category shall be used

. (2) If GOR cannot be determined from your available data, then you must use one of the

two procedures specified in paragraph s (m)(2 )(i) or (m)(2)(ii ) of this section to determine GOR :
. (i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists. (ii) Or you You may use an industry standard practice as described in §98.234(b). (3) Estimate venting emissions using Equation W-18 of this section. Formatted: NonePage 52 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. , ,, , , 1 1 y x
sn pq pq p q p q q p 

### E GOR V 

# SG E RE

  

###   



#  (Eq. W-18)

Where:

E a E s ,n = Annual volumetric natural gas emissions , at the facility level, from associated gas venting under actual at standard conditions, in cubic feet. GOR p,q

= Gas to oil ratio, for well p in sub-basin q, in standardcubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities. V p,q = Volume of oil produced, for well p in sub-basin q, in barrels in the calendar year during time periods in which associated gas was vented or flared. SG p,q = Volume of associated gas sent to sales, for well p in sub-basin q, in standard cubic feet of gas in the calendar year during time periods in which associated gas was vented or flared. ERE p,q = Emissions reported elsewhere, volume of associated gas for well p in subbasin q, in standard cubic feet, during time periods in which associated gas was vented or flared and for which emission source types of this section calculate and report emissions from the associated gas stream prior to venting or flaring of the associated gas (i .e., §98.233(j) for onshore production storage tanks). x = Total number of wells in sub-basin that vent or flare associated gas. y = Total number of sub-basins in a basin that contain wells that vent or flare associated gas. (4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. ( 5 4 ) Calculate both CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. ( 6 5 ) Calculate emissions from associated natural gas to flares if emissions are routed to a flare as follows: specified in paragraphs (m)(5)(i) and (m)(5)(ii) of this section. (i) Use the associated natural gas volume and gas composition as determined in paragraph (m)(1) through ( m)( 4) of this section. Comment [EPA7]: Proposed Revised Equation.Page 53 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Use the calculation method ology of flare stacks in paragraph (n) of this section to determine associated gas emissions from the flare. (n) Flare stack emissions . Calculate CO 2 , CH 4 , and N 2 O emissions from a flare stack as follows: specified in paragraphs (n)(1) through (n)(9) of this section. (1) If you have a continuous flow measurement device on the flare, you must use the measured flow volumes to calculate the flare gas emissions. If all of the flare gas is not measured by the existing flow measurement device, then the flow not measured can be estimated using engineering calculations based on best available data or company records. If you do not have a continuous flow measurement device on the flare, you can install a flow measuring device on the flare or use engineering calculations based on process knowledge, company records, and best available data. (2) If you have a continuous gas composition analyzer on gas to the flare, you must use these compositions in calculating emissions. If you do not have a continuous gas composition analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare as follows: specified in paragraphs (n)(2)(i) through (n)(2)(iii) of this section. (i) For onshore natural ga s production, determine natural gas composition the GHG mole fraction using paragraph (u)(2)(i) of this section. (ii) For onshore natural gas processing, when the stream going to flare is natural gas, use the GHG mole percent fraction in feed natural gas for all streams upstream of the de-methanizer or dew point control, and GHG mole percent fraction in facility specific residue gas to transmission pipeline systems for all emission s sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities. For onshore naturalPage 54 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. gas processing plants that solely fractio nate a liquid stream, use the GHG mole percent fraction in feed natural gas liquid for all streams. (iii) For any applicable industry segment, when the stream going to the flare is a hydrocarbon product stream, such as methane, et hane, propane, butane, pentane-plus and mixed light hydrocarbons, then you may use a representative composition from the source for the stream determined by engineering calculation based on process knowledge and best available data. (3) Determine flare combustion efficiency from manufacturer. If not available, assume that flare combustion efficiency is 98 percent. (4) Calculate Convert GHG volumetric emissions to standard conditions using calculations in paragraph (t) of this section. (5) Calculate GHG volumetric emissions from flaring at actual standard conditions using Equations W-19 , W

- 20, and W- 21 20 of this section. 

###   4 , 4 * *1 * s CH s CH L U E VX Z Z        (Eq. W-19) 

#   5 ,2 2 1 * *** * s s CO CO s j j L j E VX VY R Z 

   

##  (Eq. W-20)

(Eq. W

- 21)
Where:

E a ,CH4 (un

- combusted) = Contribution of annual un

- combusted CH 4 emissions from flare stack in cubic feet, under actual conditions. E a ,CO2 (un

- combusted) = Contribution of annual un

- combusted CO 2 e missions from flare stack in cubic feet, under actual conditions. E a, CO2 (combusted) = Contribution of annual combusted CO 2 emissions from flare stack in cubic feet, under actual conditions. Comment [EPA8]: Proposed Revised Equation.

Comment [EPA9]: Proposed: Equation W-20 removed; Equation W-21 revised and renumbered to W-20.Page 55 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. E s,CH4 = Annual CH 4 emissions from flare stack in cubic feet, at standard conditions. E s,CO2 = Annual CO 2 emissions from flare stack in cubi c feet, at standard conditions. V a V s = Volume of gas sent to flare in standard cubic feet, during the year as determined in paragraph (n)(1) of this section

. η = Flare combustion efficiency, expressed as F f raction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, η is zero. X CH4 = Mole fraction of CH 4 in the feed gas to the flare as determined in paragraph (n)(2) of this section. X CO2 = Mole fraction of CO 2 in the feed gas to the flare as determined in paragraph (n)(2) of this section. Z U = Fraction of the feed gas sent to an un-lit flare determined by engineering estimate and process knowledge based on best available data and operating records

. X CO2 = Mole fraction of CO 2 in gas to the flare

. Z L = Fraction of the feed gas sent to a burning flare (equal to 1- Z U ). Y

j = Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes-plus ). ) in the feed gas to the flare as determined in paragraph (n)(1) of this section. R

j = Number of carbon atoms in the gas hydrocarbon constituent j in the feed gas to the flare : 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes-plus). ( 5) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (6) Calculate both CH 4 and CO 2 mass emissions from volumetric CH 4 and CO 2 emissions using calculation in paragraph (v) of this section. (7) [Reserved] (8) Calculate N 2 O emissions from flare stacks using Equation W-40 in paragraph (z) of this section. ( 9 8 ) If you operate and maintain a CEMS that has both a CO 2 concentration monitor and volumetric flow rate monitor for the combustion gases from the flare , you must calculate onlyPage 56 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. CO 2 emissions for the flare. You must follow the Tier 4 Calculation Method ology and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). If a CEMS is used to calculate flare stack emissions, the requirements speci fied in paragraphs (n)(1) through (n)(7) are not required. If a CO 2 concentration monitor and volumetric fl ow rate monitor are not available, you may elect to install a CO 2 concentration monitor and a volumetric flow rate monitor that comply with all of the requirements speci fied for the Tier 4 Calculation Methodo logy in subpart C of this part (General Stationary Fuel Combustion). ( 10 9 ) The flare emissions determined under pa ragraph (n) of this section must be corrected for flare emissions calculated and report ed under other paragraphs of this section to avoid double counting of these emissions. (o) Centrifugal compressor venting

. Calculate CH 4 , CO 2 and N 2 O (when flared) emissions from both wet seal and dry seal centrifugal compressor vents as follows: (1) For each centrifugal compressor covered by § 98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) you must conduct an annual measurement in the operating mode in which it is found. Measure emissions from all vents (including emis sions manifolded to common vents) including wet seal oil degassing vents, unit isolation v alve vents, and blowdown valve vents. Record emissions from the following vent types in the specified compressor modes during the annual

measurement. (i) Operating mode, blowdown valve leakage through the blowdown vent, wet seal and dry seal compressors. (ii) Operating mode, wet seal oil degassing vents.Page 57 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iii) Not operating, depressurized mode, unit isolation valve leakage through open blowdown vent, without blind flanges, wet seal and dry seal compressors. (A) For the not operating, depressurized mode, ea ch compressor must be measured at least once in any three consecutive calendar years. If a compressor is not operated and has blind flanges in place throughout the 3 year period, measurement is not required in this mode. If the compressor is in standby dep ressurized mode without blind flanges in place and is not operated throughout the 3 year period, it must be measured in the standby depressurized mode. (2) For wet seal oil degassing vents, determine vapor volumes sent to an atmospheric vent or flare, usin g a temporary meter such as a vane anemometer or permanent flow meter according to 98.234(b) of this section. If you do not have a permanent flow meter, you may install a permanent flow meter on the wet seal oil degassing tank vent. (3) For blowdown valve leakage and unit isolation valve leakage to open ended vents, you can use one of the following methods: Calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. For through valve leakage, such

as isolation valves, you may use an acoustic leak detection device according to methods set forth
in § 98.234(a). If you do not have a flow meter, you may install a port for insertion of a temporary meter, or a perman ent flow meter, on the vents. (4) Estimate annual emissions using the flow measurement and Equation W

- 22 of this section. ) 1 ( * * *

, , , m m i m m m i s B M T MT E

  (Eq. W

- 22)
Where:
E s,i,m = Annual GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions, in cubic feet.Page 58 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. MT m = Measured gas emissions in standard cubic feet per hour.
T m = Total time the compressor is in the mode for which E s,i is being calculated, in the calendar year in hours.
M i,m = Mole fraction of GHG i in the vent gas; use the appropriate gas compositions in paragraph (u)(2) of this section.
B m = Fraction of operating time that the vent gas is sent to vapor recovery or fuel gas as determined by keeping logs of the number of operating hours for the vapor recovery system and the time that vent gas is directed to the fuel gas system or s ales. (5) Calculate annual emissions from each centrifugal compressor using Equation W

- 23 of this section.

, , * * s im m m i E EF T GHG  (Eq. W

- 23)
Where:
E s,i,m = Annual total volumetric GHG emissions at standard conditions from each centrifugal compressor for mode

- source combination m, in cubic feet.
EF m = Reporter emission factor for each mode m, in cubic feet per hour, from Equation W

- 24 of this section as calculated in paragraph 6.
T m = Total time in hours per year the compressor was in each mode, as lis ted in paragraph (o)(1)(i) through (o)(1)(iii).
GHG i = For onshore natural gas processing facilities, concentration of GHG i , CH 4 or CO 2 , in produced natural gas or feed natura l gas; for other facilities listed in § 98.230(a)(4) through (a)(8),GHG i equals 1. (6) You shall use the flow measurements of operating mode wet seal oil degassing vent, operating mode blowdown valve vent and not operating depressurized mode isolation valve ventPage 59 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. for all the reporter's compressor modes not measured in the calendar year t o develop the following emission factors using Equation W

- 24 of this section for each emission source and mode as listed in paragraph (o)(1)(i) through (o)(1)(iii).

, 1 m Count

m p p m m 

### M

T EF Count  

###  

#  (Eq. W

- 24)

Where:
EF m = Reporter emission factors for compressor in the three modes m (as listed in paragraph (o)(1)(i) through (o)(1)(iii)) in cubic feet per hour.
MT m,p = Flow measurements from all centrifugal compressor sources in each mode

- source combination, m, for each measured compressor, p, in standar d cubic feet per hour.
Count m = Total number of compressors measured.

m = Compressor mode

- source combination as listed in paragraphs (o)(1)(i) through (o)(1)(iii). (i) The emission factors must be calculated annually. You must use all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar years of measurements in paragraph (o)(6) of this section. (ii) [Reserved] (7) Onshore petroleum and natural gas production shall calculate emissions from centrifugal compressor wet seal oil degassing vents as follows:

i i s EF Count E *

,  (Eq. W

- 25)
Where:Page 60 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. E s,i = Annual total volumetric GHG emissions at standard conditions from centrifugal compressor wet seals in cubic feet.
Count = Total number of centrifugal compressors for the reporter.
EF i = Emission factor for GHG i . Use 1.2 × 10 7 standard cubic feet per year per compressor for CH 4 and 5.30 × 10 5 standard cubic feet per year per compressor for CO 2 at 60 °F and 14.7 psia. (8) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (9) Calculate emissions from seal oil dega ssing vent vapors to flares as follows: (i) Use the seal oil degassing vent vapor volume and gas composition as determined in paragraphs (o)(5) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine degassing vent vapor emissions from the flare. If you are required to report emissions from centrifugal compressor venting as specified in §98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (o)(5) of this section; perform cal culations specified in pa ragraphs (o)(6) through (o)(9) of this section; and calculate CH 4 and CO 2 mass emissions as specified in paragraph (o)(11) of this section. If emissions from a comp ressor source are routed to a flare, paragraphs (o)(1) through (o)(11) of this section do not apply and instead you must calculate CH 4 , CO 2 , and
N 2 O emissions as specified in paragraph (o)(12) of this section. If emissions from a compressor source are captured for fuel use or are routed to a thermal oxidizer, paragraphs (o)(1) through (o)(12) of this section do not apply and instead you must calculate and report emissions asPage 61 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. specified in subpart C of this part. If emissions from a compressor source are routed to vapor recovery, the calculations specified in paragraphs (o)(1) through (o)(12) of this section do not apply. If you are required to report emissions from centrifugal compressor venting at an onshore petroleum and natural gas production facility as specified in §98.232(c)(19), you must calculate volumetric emissions as specified in paragrap h (o)(10) of this sec tion; and calculate CH 4 and
CO 2 mass emissions as specified in paragraph (o)(11) of this section. (1) General requirements for conducting volumetric emission measurements . You must conduct volumetric emission measurements on each centrifugal compressor as specified in this paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a measurement method specified in paragraph (o)(1)(i) or (o)(1)(ii) of this section. Manifolded compressor sources (as defined in § 98.238) must use a measurement method specified in paragraph (o)(1)(i), (o)(1)(ii), (o)(1)(iii), or (o)(1)(iv) of this section. (i) Centrifugal compressor source as found leak measurements. Measure venting from each compressor according to either paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraphs (o)(1)(i)(C) and (o)(1)(i)(D) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable mo nitoring and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this section. (A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (o)(2)(i)(A) or (o)(2)(i)(B) of this s ection and, if the compressor has wet seal oilPage 62 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. degassing vents, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section. If a compre ssor has a continuously operating vapor recovery system for the wet seal degassing, then measurement of wet seal degassing is not required. (B) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in either paragraph (o)(2)(i)(A), (o)(2)(i)(B), or (o)(2)(i)(C) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode. (C) You must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section at least once in any three consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If three consecutive calendar years occur without measuring the compressor in not-operating-depressurized-mode, you must measure the compressor as specified in paragraph (o)(1)(i)(B) of this sectio n at the next scheduled depressurized shutdown. The requirement specified in this paragraph does not apply if the compressor has blind flanges in place throughout the reporting year. (D) You must measure the compressor as specified in paragraph (o)(1)(i)(A) of this section at least once in any three consecutive calendar years, provided that the measurement can be taken when the compressor is in operating-mode. If three consecutive calendar years occur without measuring the compressor in operating-mode, you must measure the compressor as specified in paragraph (o)(1)(i)(A) of this section in the next calendar year that the compressor is in operating-mode for more than 2,000 hours. (ii) Centrifugal compressor source continuous monitoring. Instead of measuring the compressor source according to paragraph (o)(1)(i) of this section for a given compressor, youPage 63 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. may elect to continuously measure volumetric em issions from a compressor source as specified in paragraph (o)(3) of this section. (iii) Manifolded centrifugal compressor source as found leak measurements. For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (o)(1)(i), (o)(1)(ii), or (o)(1)(iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting leak measurements at the common vent stack as specified in paragraph (o)(4) of this section. The leak measurements must be conducted at the frequency specified in paragraphs (o)(1 )(iii)(A) through (o)(1)(iii)(C) of this section. (A) A minimum of three leak measurements must be taken for each manifolded group of compressor sources in a calendar year. (B) The leak measurements may be performed while the compressors are in any compressor mode. (C) The three required leak measurements must be separated by a minimum of 60 days. If more than two leak measurements are performed, the first and last measurements in a calendar year must be separated by a minimum of 120 days. (iv) Manifolded centrifugal compressor source continuous monitoring. For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (o)(1)(i), (o)(1)(ii), or (o)(1)(iii) of this section, you may elect to continuously measure combined volum etric emissions from the manifolded group of compressor sources as specified in paragraph (o)(5) of this section. (2) Methods for performing as found leak measurements from individual centrifugal
compressor sources . If conducting leak measurements for each compressor source, you mustPage 64 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. determine the volumetric emissions of leaks fro m blowdown valves and isolation valves as specified in paragraph (o)(2)(i) of this section, and the volumetric emissions of leaks from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section. (i) For blowdown valves on compressors in operating-mode and for isolation valves on compressors in not-operating-depressurized-mode, determine the volumetric emissions of leaks using one of the methods specified in paragraphs (o )(2)(i)(A) through (o)(2)(i)(C) of this section. (A) Measure the volumetric flow at standa rd conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. (B) Measure the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer according to methods set forth in § 98.234(b). (C) For isolation valves, you may use an ac oustic leak detection device according to methods set forth in § 98.234(a) instead of measuring the isolation valve leakage through the blowdown vent as provided for in paragraphs (o)(2)(i)(A) or (o)(2)(i)(B) of this section. (ii) For wet seal oil degassing vents in operating-mode, determine vapor volumes at standard conditions, using a temporary meter such as a vane anemometer or permanent flow meter according to methods set forth in § 98.234(b). (3) Methods for continuous leak measurement from individual centrifugal compressor

sources . If you elect to conduct continuous volumetric emission measurements for an individual compressor source as specified in paragraph (o )(1)(ii) of this section, you must measure volumetric emissions as specified in paragraphs (o)(3)(i) and (o)(3)(ii) of this section. (i) Continuously measure the volumetric fl ow for the individual compressor source at standard conditions using a permanent meter according to methods set forth in § 98.234(b).Page 65 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(3)(i) of this section, the compresso r blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (4) Methods for performing as found leak measurements from manifolded groups of centrifugal compressor sources . If conducting leak measurements for a manifolded group of compressor sources, you must measure volumetric emissions of leaks as specified in paragraphs (o)(4)(i) and (o)(4)(ii) of this section. (i) Measure at a single point in the manifo ld downstream of all compressor inputs and where emissions cannot be comingled with other non-compressor emission sources. (ii) Determine the volumetric flow at stan dard conditions from the common stack using one of the methods specified in paragraphs (o)( 4)(ii)(A) through (o)(4)(ii)(C ) of this section. (A) A temporary meter such as a vane anemometer according the methods set forth in § 98.234(b). (B) Calibrated bagging according to methods set forth in § 98.234(c). (C) A high volume sampler according to methods set forth § 98.234(d). (5) Methods for continuous leak measurement from manifolded groups of centrifugal
compressor sources . If you elect to conduct continuous volumetric emission measurements for a manifolded group of compressor sources as specified in paragraph (o)(1)(iv) of this section, you must measure volumetric emissions as specified in paragraphs (o)(5)(i) through (o)(5)(iii) of this section. (i) Measure at a single point in the manifo ld downstream of all compressor inputs and where emissions cannot be comingled with other non-compressor emission sources.Page 66 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(5)(ii) of this section, the comp ressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (6) Method for calculating volumetric GHG em issions from as found leak measurements for individual centrifugal compressor sources . For compressor sources measured according to paragraph (o)(1)(i) of this section, you must calculate annual GHG emissions from the compressor sources as specified in paragraphs (o)(6)(i) through (o)(6)(iv) of this section. (i) Using Equation W-21 of this section, calculate the annual volumetric GHG emissions for each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) and (o)(1)(i)(B) of this section that was measured during the reporting year.

m i m m s m i s 

### GHG T MT E

, , , , 

### * *  (Eq. W-21)

Where:

E s,i,m = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions for measured compressor mode-source combination m, at standard conditions, in cubic feet. MT s,m = Volumetric gas emissions for measured compressor mode-source combination m, in standard cubic feet per hour, measured according to paragraph (o)(2) of this section. If mu ltiple measurements are performed for a given mode-source combination m, use the average of all measurements.Page 67 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. T m = Total time the compressor is in th e mode-source combination for which E s,i,m is being calculated in the reporting year, in hours. GHG i,m = Mole fraction of GHG i in the vent gas for measured compressor mode-source combination m; use the appropriate gas compositions in paragraph (u)(2) of this section. m = Compressor mode-source combination sp ecified in paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section that was measured for the reporting year. (ii) Using Equation W-22 of this section, calculate the annual volumetric GHG emissions from each centrifugal compressor mode-source combination specified in paragraph (o)(1)(i)(A) and (o)(1)(i)(B) of this section that was not measured during the reporting year.

m i m s m m i s 

### GHG T EF E

, , , , 

### * *  (Eq. W-22)

Where:

E s,i,m = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions for unmeasured compressor mode-source combination m, at standard conditions, in cubic feet. EF m,s = Reporter emission factor for compressor mode-source combination m, in standard cubic feet per hour, as calculated in paragraph (o)(6)(iii) of this section. T m = Total time the compressor was in the unmeasured mode-source combination m, for which E s,i,m is being calculated in the reporting year, in hours. GHG i,m = Mole fraction of GHG i in the vent gas for unmeasured compressor modesource combination m; us e the appropriate gas co mpositions in paragraph (u)(2) of this section. m = Compressor mode-source combination sp ecified in paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section that was not measured in the reporting year. (iii) Using Equation W-23 of this section, develop an emission factor for each compressor mode-source combination specified in paragraph (o)(1)(i)(A) and (o)(1)(i)(B) of this section. These emission factors must be used in Equation W-23 of this section to determine Field Code ChangedPage 68 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. volumetric emissions from a centrifugal compressor in the mode-source combinations that were not measured in the reporting year.



### EF MT Count m s mps p Count

m m

, , ,



###   

# 

1 (Eq. W-23)

Where:

EF m,s = Reporter emission factor to be used in Equation W-23 of this section for compressor mode-source combination m, in standard cubic feet per hour. The reporter emission factor must be based on all compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years. MT m,p,s = Average volumetric gas emission measurement for compressor mode-source combination m, for compressor p, in standard cubic feet per hour, calculated using all volumetric gas emission measurements (MTm in Equation W-21 of this section) for compressor mode-sou rce combination m for compressor p in the current reporting year and the preceding two reporting years. Count m = Total number of compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years. m = Compressor mode-source combination sp ecified in paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section. (iv) The reporter emission factor in Equation W-23 of this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities fo r the owner or operator. (7) Method for calculating volumetric GHG emissions from continuous monitoring of individual centrifugal compressor sources . For compressor sources measured according to paragraph (o)(1)(ii) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (o)(3) of this section and calculate annual Field Code ChangedPage 69 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. volumetric GHG emissions associated with the co mpressor source using Equation W-24A of this section.

v i v s v i s 

### GHG Q E

, , , , 

### *

 (Eq. W-24A)

Where:

E s,i,v = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions from compressor source v, at standard conditions, in cubic feet. Q s,v = Volumetric gas emissions from compressor source v, for reporting year, in standard cubic feet.
GHG i,v = Mole fraction of GHG i in the vent gas for compressor source v; use the appropriate gas compositions in paragraph (u)(2) of this section. (8) Method for calculating volumetric GHG emissions from as found leak measurements of manifolded groups of centrifugal compressor sources. For manifolded groups of compressor sources measured according to paragraph (o)(1)(iii) of this section, you must calculate annual volumetric GHG emissions using Equation W-24B of this section.

g i avg g g i s 

### GHG MT E

, , , , 

### * * 8760  (Eq. W-24B)

Where:

E s,i,g = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions for manifolded group of compressor sources g, at standard conditions, in cubic feet. MT g,avg = Average volumetric gas emissions of all measurements performed in the reporting year according to paragraph (o)(4) of this section for the manifolded group of compressor sources g, in standard cubic feet per hour. GHG i,g = Mole fraction of GHG i in the vent gas for manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section. Field Code ChangedPage 70 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of centrifugal compressor sources . For a manifolded group of compressor sources measured according to paragraph (o)(1)(iv) of this section, you must use the continuous volumetric emission measurements taken as specifi ed in paragraph (o)(5) of this section and calculate annual volumetric GHG emissions associated with each manifolded group of compressor sources using Equation W-24C of this section. If the centrifugal compressors included in the manifolded group of compressor sources share the manifold with reciprocating compressors, you must follow the procedures in ei ther this paragraph (o)(9) or paragraph (p)(9) of this section to calculate emissions from the manifolded group of compressor sources.

g i g s g i s 

### GHG Q E

, , , , 

### *

 (Eq. W-24C)

Where:

E s,i,g = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions from manifolded group of compressor sources g, at standard conditions, in cubic feet. Q s,g = Volumetric gas emissions from manifolded group of compressor sources g, for reporting year, in standard cubic feet. GHG i,g = Mole fraction of GHG i in the vent gas for measured manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section. (10) Method for calculating volumetric GHG emissions from wet seal oil degassing vents at an onshore petroleum and natural gas production facility . You must calculate emissions from centrifugal compressor wet seal oil degassing vents at an onshore petroleum and natural gas production facility using Equation W-25 of this section.

s i i s 

### EF Count E

,

, 

### *  (Eq. W-25)

Where:Page 71 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. E s,i = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions from centrifugal compressor wet seals, at standard conditions, in cubic feet. Count = Total number of centrifugal compre ssors that have wet seal oil degassing vents. EF i,s = Emission factor for GHG i . Use 1.2 × 10 7 standard cubic feet per year per compressor for CH 4 and 5.30 × 10 5 standard cubic feet per year per compressor for CO 2 at 60 °F and 14.7 psia. (11) Method for converting fro m volumetric to mass emissions . You must calculate both
CH 4 and CO 2 mass emissions from volumet ric emissions using calculations in paragraph (v) of this section. (12) General requirements for calculating volumetric GHG emissions from centrifugal compressors routed to flares . You must calculate and report emissions from all centrifugal compressor sources that are routed to a flare as specified in paragraphs (o)(12)(i) through (o)(12)(iii) of this section. (i) Emissions calculations under this paragraph (o) of this section are not required for compressor sources that are routed to a flare. (ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as specified in paragraph (n) of this secti on and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attr ibutable to compressor sources from the flare. (iii) Report all applicable ac tivity data for compressors with compressor sources routed to flares as specified in § 98.236(o). (p) Reciprocating compressor venting

. Calculate CH 4 and CO 2 emissions fr om all reciprocating compressor vents as follows. Fo r each reciprocating compressor covered in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must conduct an annual measurement for each compressor in the mode in which it is foun d during the annual measurement, except as specifiedPage 72 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. in paragraph (p)(9) of this section. Measure emissions from (including emissions manifolded to common vents) reciprocating rod packing vents, unit isolation valve vents, and blowdown valve vents. Record emissions from the following vent types in the specified compressor modes during the annual measurement as follows: (1) Operating or standby pressurized mode, blowdown vent leakage through the blowdown vent stack. (2) Operating mode, reciprocating rod packing emissions. (3) Not operating, depressurized mode, unit isolation valve leakage through the blowdown vent stack, without blind flanges. (i) For the not operating, depressurized mode, ea ch compressor must be measured at least once in any three consec utive calendar years if this mode is not found in the annual measurement. If a compressor is not operated and has blind flanges in place throughout the 3 year period, measurement is not required in this mode. If the compressor is in standby depressurized m ode without blind flanges in place and is not operated throughout the 3 year period, it must be measured in the standby depressurized mode. (ii) [Reserved] (4) If reciprocating rod packing and bl owdown vent are connected to an open

- ended vent line use one of the following two methods to calculate emissions: (i) Measure emissions from all vents (including emissions manifolded to common vents) including rod packing, unit isolation valves, an d blowdown vents using either calibrated bagging or high volume sampl er according to methods set forth in § 98.234(c) and § 98.234(d), respectively. Formatted: Level 2Page 73 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Use a temporary meter such as a vane anemometer or a permanent meter such as an orifice meter to measure emissions from all vent s (including emissions manifolded to a common vent) including rod packing vents and unit isolation valve leakage through blowdown vents according to methods set forth in § 98.234(b). If you do not have a permanent flow meter, you may install a port for insertion of a temporary meter or a permanent flo w meter on the vents. For through

- valve leakage to open ended vents, such as unit isolation valves on not operating, depressurized compressors and blowdown valves on pressurized compressors, you may use an acoustic detection device according to methods set forth in § 98.234(a). (5) If reciprocating rod packing is not equipped with a vent line use the following method to calculate emissions: (i) You must use the methods described in § 98.234(a) to conduct annual leak detection of equipment leaks from the packi ng case into an open distance piece, or from the compressor crank case breather cap or other vent with a closed distance piece. (ii) Measure emissions found in paragraph (p)(5 )(i) of this section using an appropriate meter, or calibrated bag, or high volum e sampler according to methods set forth in § 98.234(b), (c), and (d), respectively. (6) Estimate annual emissions using the flow measurement and Equation W

- 26 of this section.

m i m m m i s M T MT E

, , , * *  (Eq. W

- 26)
Where:
E s,i,m = Annual GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions, in cubic feet.
MT m = Measured gas emissions in standard cubic feet per hour.Page 74 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. T m = Total time the compressor is in the mode for which E s,i,m is being calculated, in the calendar year in hours.
M i,m = Mole f raction of GHG i in gas; use the appropriate gas compositions in paragraph (u)(2) of this section. (7) Calculate annual emissions from each reciprocating compressor using Equation W

- 27 of this section.

, , * * s im m m i E EF T GHG  (Eq. W

- 27)
Where:
E s,i,m = Annual total volumetric GHG emissions at standard conditions from each reciprocating compressor for mode

- source combination m, in cubic feet.
EF m = Reporter emission factor for each mode, m, in cubic feet per hour, from Equation W

- 28 of this section as ca lculated in paragraph (p)(7)(i) of this section.
T m = Total time in hours per year the compressor was in each mode, m, as listed in paragraph (p)(1) through (p)(3).
GHG i = For onshore natural gas processing facilities, concentration of GHG i, CH 4 or CO 2 , i n produced natural gas or feed natura l gas; for other facilities listed in § 98.230(a)(4) through (a)(8), GHG i equals 1.

m = Compressor mode as listed in paragraph (p)(1) through (p)(3). (i) You shall use the flow meter readings from measurements of operating and standby pressurized blowdown vent, operating mode vents, not operating depressurized isolation valve vent for all the reporter's compressor modes not measured in the calendar year to develop the following emission factors using Equation W

- 28 of this section for each mode as listed in paragraph (p)(1) through (p)(3).Page 75 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. , 1 m Count

m p p m m 

### M

T EF Count  

###  

#  (Eq. W

- 28)

Where:
EF m = Reporter emission factors for compressor in the three modes, m, in cubic feet per hour.
MT m,p = Flow measurements from all reciprocating compressor sources in each mode

- source combination, m, for each measured compressor, p, in standard cubic feet per hour.
Count m = Total number of compressors measured in each mode, m.

m = Compressor mode

- source combination as listed in (p)(1) through (p)(3). (A) You must combine emissions for blowndown vents, measured in the operating and standby pressurized modes. (B) The emission factors must be calculated annually. You must use all measurements from the current calendar year and the precedi ng two calendar years, totaling three consecutive calendar years of measurements. (ii) [Reserved] (8) Determine if the reciprocating compressor vent vapors are sent to a vapor recovery system. (i) Adjust the emissions estimate d in paragraphs (p)(7) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data. (ii) [Reserved]Page 76 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (9) Onshore petroleum and natural gas production shall calculate emissions from reci procating compressors as follows:

i i s EF Count E *

,  (Eq. W

- 29)
Where:
E s,i = Annual total volumetric GHG emissions at standard conditions from reciprocating compressors in cubic feet.
Count = Total number of reciprocating compressors for the reporter.
EF i = Emission factor for GHG i . Use 9.48 × 10 3 standard cubic feet per year per compressor for CH 4 and 5.27 × 10 2 standard cubic feet per year per compressor for CO 2 at 60 °F and 14.7 psia. (10) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in para graphs (u) and (v) of this section. If you are required to report emissions fr om reciprocating compressor venting as specified in §98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct volumetric emission measurements specified in paragraph (p)( 1) of this section using methods specified in paragraphs (p)(2) through (p)(5) of this section; perform calculations specified in paragraphs (p)(6) through (p)(9) of this section; and calculate CH 4 and CO 2 mass emissions as specified in paragraph (p)(11) of this section. If emissions from a compressor source are routed to a flare, paragraphs (p)(1) through (p)(11) of this sect ion do not apply and instead you must calculate
CH 4 , CO 2 , and N 2 O emissions as specified in paragraph (p)(12) of this section. If emissions from a compressor source are captured for fuel use or are routed to a thermal oxidizer, paragraphs (p)(1) through (p)(12) of this section do not apply and instead you must calculate and report emissions as specified in subpart C of this part . If emissions from a compressor source are routedPage 77 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. to vapor recovery, the calculations specified in paragraphs (p)(1) through (p)(12) of this section do not apply. If you are required to report emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility as specified in §98.232(c)(11), you must calculate volumetric emissions as specified in pa ragraph (p)(10) of this section; and calculate
CH 4 and CO 2 mass emissions as specified in paragraph (p)(11) of this section. (1) General requirements for conducting volumetric emission measurements . You must conduct volumetric emission measurements on each reciprocating compressor as specified in this paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a measurement method specified in paragraph (p)(1)(i) or (p)(1)(ii) of this section. Manifolded compressor sources (as defined in § 98.238) must use a measurement method specified in paragraph (p)(1)(i), (p)(1)(ii), (p)(1)(iii), or (p)(1)(iv) of this section. (i) Reciprocating compressor source as found leak measurements. Measure venting from each compressor according to either paragraph (p)(1 )(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraph (p)(1)(i)(D) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable mo nitoring and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this section. (A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (p)(2)(i)(B) of this section, and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) of this section.Page 78 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) For a compressor measured in standby-pressurized-mode, you must measure volumetric emissions from blowdown valve leakag e through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (p)(2)(i)(B) of this section. (C) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in either paragraph (p)(2)(i)(A), (p)(2)(i)(B), or (p)(2)(i)(C) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode. (D) You must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at least once in any three consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If there is no scheduled shutdown within three consecutive calendar years, you must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section either prior to or during the next compressor shutdown when the replacement of the compressor rod packing occurs. (ii) Reciprocating compressor source continuous monitoring. Instead of measuring the compressor source according to paragraph (p)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric em issions from a compressor source as specified in paragraph (p)(3) of this section. (iii) Manifolded reciprocating compressor source as found leak measurements. For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (p)(1)(i), (p)(1)(ii), or (p)(1)(iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting leak measurements at the common ventPage 79 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. stack as specified in paragraph (p)(4) of this section. The leak measurements must be conducted at the frequency specified in paragraphs (p)(1 )(iii)(A) through (p)(1)(iii)(C) of this section. (A) A minimum of three leak measurements must be taken for each manifolded group of compressor sources in a calendar year. (B) The leak measurements may be performed while the compressors are in any compressor mode. (C) The three required leak measurements must be separated by a minimum of 60 days. If more than three leak measurements are performed, the first and last measurements in a calendar year must be separated by a minimum of 120 days. (iv) Manifolded reciprocating compressor source continuous monitoring. For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (p)(1)(i), (p)(1)(ii), or (p)(1)(iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded group of compressors sources as specified in paragraph (p)(5) of this section. (2) Methods for performing as found leak measurements from individual reciprocating
compressor sources . If conducting leak measurements for each compressor source, you must determine the volumetric emissions of leaks fro m blowdown valves and isolation valves as specified in paragraph (p)(2)(i) of this section. You must determ ine the volumetric emissions of leaks from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (p)(2)(iii) of this section.(i) For blowdown valves on compressors in operating-mode or standby-pressurizedmode, and for isolation valves on compressors in not-operating-depressurized-mode, determinePage 80 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. the volumetric emissions of leaks using one of th e methods specified in paragraphs (p)(2)(i)(A) through (p)(2)(i)(C) of this section. (A) Measure the volumetric flow at standa rd conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. (B) Measure the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b). (C) For isolation valves, you may use an ac oustic leak detection device according to methods set forth in § 98.234(a) instead of measuring the isolation valve leakage through the blowdown vent as provided for in paragraphs (p)(2)(i)(A) or (p)(2)(i)(B) of this section. (ii) For reciprocating rod packing equipped with an open-ended vent line on compressors in operating-mode, determine the volumetric emissions of leaks using one of the methods specified in paragraphs (p)(2)(ii)(A ) and (p)(2)(ii)(B) of this section. (A) Measure the volumetric flow at standard conditions from the open-ended vent line using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. (B) Measure the volumetric flow at standard conditions from the open-ended vent line using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b). (iii) For reciprocating rod packing not equipped with an open-ended vent line on compressors in operating-mode, you must determin e the volumetric emissions of leaks using the method specified in paragraphs (p)(2)(iii)(A) and (p)(2)(iii)(B) of this section.Page 81 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (A) You must use the methods described in §98.234(a) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or from the compressor crank case breather cap or other vent with a closed distance piece. (B) You must measure emissions found in pa ragraph (p)(2)(iii)(A) of this section using an appropriate meter, calibrated bag, or high volume sampler according to methods set forth in §98.234(b), (c), and (d), respectively. (3) Methods for continuous leak measurement from individual reciprocating compressor

sources . If you elect to conduct continuous volumetric emission measurements for an individual compressor source as specified in paragraph (p )(1)(ii) of this section, you must measure volumetric emissions as specified in paragraphs (p)(3)(i) and (p)(3)(ii) of this section. (i) Continuously measure the volumetric flow for the individual compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(3)(i) of this section, the compresso r blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (4) Methods for performing as found leak measurements from manifolded groups of reciprocating compressor sources . If conducting leak measurements for a manifolded group of compressor sources, you must measure volumetric emissions of leaks as specified in paragraphs (p)(4)(i) and (p)(4)(ii) of this section. (i) Measure at a single point in the manifo ld downstream of all compressor inputs and where emissions cannot be comingled with other non-compressor emission sources.Page 82 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Determine the volumetric flow at sta ndard conditions from the common stack using one of the methods specified in paragraph (p)(4)(ii)(A) through (p)(4)(ii)(C). (A) A temporary meter such as a vane anemometer according the methods set forth in § 98.234(b). (B) Calibrated bagging according to methods set forth in § 98.234(c). (C) A high volume sampler according to methods set forth § 98.234(d). (5) Methods for continuous leak measurement from manifolded groups of reciprocating
compressor sources . If you elect to conduct continuous volumetric emission measurements for a manifolded group of compressor sources as specified in paragraph (p)(1)(iv) of this section, you must measure volumetric emissions as specified in paragraphs (p)(5)(i) through (p)(5)(iii) of this section. (i) Measure at a single point in the manifo ld downstream of all compressor inputs and where emissions cannot be comingled with other non-compressor emission sources. (ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(5)(ii) of this section, the comp ressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (6) Method for calculating volumetric GHG em issions from as found leak measurements for individual reciprocating compressor sources. For compressor sources measured according toPage 83 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. paragraph (p)(1)(i) of this section, you must calculate GHG emissions from the compressor sources as specified in paragraphs (p)(6 )(i) through (p)(6)(iv) of this section. (i) Using Equation W-26 of this section, calculate the annual volumetric GHG emissions for each reciprocating compressor mode-source comb ination specified in paragraphs (p)(1)(i)(A) through (p)(1)(i)(C) of this section that was measured during the reporting year.

m i m m s m i s 

### GHG T MT E

, , , , 

### * *  (Eq. W-26)

Where:

E s,i,m = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions for measured compressor mode-source combination m, at standard conditions, in cubic feet. MT s,m = Volumetric gas emissions for measured compressor mode-source combination m, in standard cubic feet per hour, measured according to paragraph (p)(2) of this section. If mu ltiple measurements are performed for a given mode-source combination m, use the average of all measurements. T m = Total time the compressor is in th e mode-source combination m, for which E s,i,m is being calculated in the reporting year, in hours. GHG i,m = Mole fraction of GHG i in the vent gas for measured compressor mode-source combination m; use the appropriate gas compositions in paragraph (u)(2) of this section. m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this s ection that was measured for the reporting year. (ii) Using Equation W-27 of th is section, calculate the an nual volumetric GHG emissions from each reciprocating compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section that was not measured during the reporting year.

m i m s m m i s 

### GHG T EF E

, , , , 

### * *  (Eq. W-27) Field Code Changed

Field Code ChangedPage 84 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Where:

E s,i,m = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions for unmeasured compressor mode-source combination m, at standard conditions, in cubic feet. EF m,s = Reporter emission factor for compressor mode-source combination m, in standard cubic feet per hour, as calculated in paragraph (p)(6)(iii) of this section. T m = Total time the compressor was in the unmeasured mode-source combination m, for which E s,i,m is being calculated in the reporting year, in hours. GHG i,m = Mole fraction of GHG i in the vent gas for unmeasured compressor modesource combination m; us e the appropriate gas co mpositions in paragraph (u)(2) of this section. m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was not measured in the reporting year. (iii) Using Equation W-28 of this section, develop an emission factor for each compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section. These emission factors must be used in Equation W-27 of this section to determine volumetric emissions from a reciprocating compressor in the mode-source combinations that

were not measured in the reporting year. 

### EF MT Count m s mps p Count

m m

, , ,



###   

# 

1 (Eq. W

- 28)

Where:
EF m = Reporter emission factors for compressor in the three modes, m, in cubic feet per hour.
MT m,p = Flow measurements from all reciprocating compressor sources in each mode

- source combination , m, for each measured compressor , p, in standard cubic feet per hour.
Count m = Total number of compressors measured in each mode, m

. Formatted: ___GHG PARAGRAPH, None

Formatted: ___GHG PARAGRAPHPage 85 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. m = Compressor mode

- source combination as listed in (p)(1 ) through (p)( 3). (A ) You must combine emissions for blowndown vents, measured in the operating and standbypressurized modes. ( B ) The emission factors must be calculated annually. You must use all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar years of measurements. ( ii) [Reserved] (8) Determine if the reciprocating compressor vent vapors are sent to a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (p)( 7 ) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determi ned by engineering estimate based on best available data

. (ii) [Reserved] (9) Onshore petroleum and natural gas production shall calculate emissions from reciprocating compressors as follows:

v i v s v i s 

### GHG Q E

, , , , 

### *

 (Eq. W

- 29 ) Where:
E s,i = Annual total volumetric GHG emissions at standard conditionsfrom

g i avg g g i s 

### GHG MT E

, , , , 

### * * 8760  reciprocating compressors g i g s g i s GHG Q E

, , , , *

 s i i s 

### EF Count E

,

, 

### * 
in cubic feet.
Count = Total number of reciprocating compressors for the reporter

. Formatted: None

Formatted: None

Formatted: ___GHG PARAGRAPHPage 86 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. EF i = Emission factor for GHG i . Use 9.48 × 10 3 standard cubic feet per year per compressor for CH 4 and 5.27 × 10 2 standard cubic feet per year per compressor for CO 2 at 60 °F and 14.7 psia. ( 10) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in paragraphs (u) and (v) of this section.

.



### EF MT Count m s mps p Count

m m

, , ,



###   

# 

1 (Eq. W-28)

Where:

EF m,s = Reporter emission factor to be used in Equation W-27 of this section for compressor mode-source combination m, in standard cubic feet per hour. The reporter emission factor must be based on all compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years. MT m,p,s = Average volumetric gas emission measurement for compressor mode-source combination m, for compressor p, in standard cubic feet per hour, calculated using all volumetric gas emission measurements (MTm in Equation W-26 of this section) for compressor mode-sou rce combination m for compressor p in the current reporting year and the preceding two reporting years. Count m = Total number of compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years. m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. (A) Emission factors must be calculated annually for each compressor mode-source combination specified in paragraph ((p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section. (B) You must combine emissions for blowndown vents, measured in the operating and standby-pressurized modes. Field Code ChangedPage 87 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iv) The reporter emission factor in Equation W-28 of this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator. (7) Method for calculating volumetric GHG emissions from continuous monitoring of individual reciprocating compressor sources . For compressor sources measured according to paragraph (p)(1)(ii) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (p)(3) of this section and calculate annual volumetric GHG emissions associated with the co mpressor source using Equation W-29A of this section.

v i v s v i s 

### GHG Q E

, , , , 

### *

 (Eq. W-29A)
Where:

E s,i,v = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions from compressor source v, at standard conditions, in cubic feet. Q s,v = Volumetric gas emissions from compressor source v, for reporting year, in standard cubic feet. GHG i,v = Mole fraction of GHG i in the vent gas for compressor source v; use the appropriate gas compositio ns in paragraph (u)(2) of this section. (8) Method for calculating volumetric GHG em issions from as found leak measurements of manifolded groups of reciprocating compressor sources. For manifolded groups of compressor sources measured according to paragraph (p)(1)(iii) of this section, you must calculate annual GHG emissions using Equation W-29B of this section.

g i avg g g i s 

### GHG MT E

, , , , 

### * * 8760  (Eq. W-29B) Field Code Changed

Field Code ChangedPage 88 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Where:

E s,i,g = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions for manifolded group of compressor sources g, at standard conditions, in cubic feet. MT g,avg = Average volumetric gas emissions of all measurements performed in the reporting year according to paragraph (p)(4) of this section for the manifolded group of compressor sources g, in standard cubic feet per hour. GHG i,g = Mole fraction of GHG i in the vent gas for manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section. (9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of reciprocating compressor sources . For a manifolded group of compressor sources measured according to paragraph (p)(1)(iv) of this section, you must use the continuous volumetric emission measurements taken as specifi ed in paragraph (p)(5) of this section and calculate annual volumetric GHG emissions associated with each manifolded group of compressor sources using Equation W-29C of this section. If the reciprocating compressors included in the manifolded group of compressor sources share the manifold with centrifugal compressors, you must follow the procedures in either this paragraph (p)(9) or paragraph (o)(9) of this section to calculate emissions from the manifolded group of compressor sources.

g i g s g i s GHG Q E

, , , , *

 (Eq. W-29C)

Where:

E s,i,g = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions from manifolded group of compressor sources g, at standard conditions, in cubic feet. Q s,g = Volumetric gas emissions from manifolded group of compressor sources g, for reporting year, in standard cubic feet. GHG i,g = Mole fraction of GHG i in the vent gas for measured manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section. Field Code ChangedPage 89 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (10) Method for calculating volumetric GHG emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility . You must calculate emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility using Equation W-29D of this section.

s i i s 

### EF Count E

,

, 

### *  (Eq. W-29D)

Where:

E s,i = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions from reciprocating compressors, at standard conditions, in cubic feet. Count = Total number of reciprocating compressors. EF i,s = Emission factor for GHG i . Use 9.48 × 10 3 standard cubic feet per year per compressor for CH 4 and 5.27 × 10 2 standard cubic feet per year per compressor for CO 2 at 60 °F and 14.7 psia. (11) Method for converting fro m volumetric to mass emissions . You must calculate both
CH 4 and CO 2 mass emissions from volumet ric emissions using calculations in paragraph (v) of this section. (12) General requirements for calculating vo lumetric GHG emissions from reciprocating compressors routed to flares . You must calculate and report emissions from all reciprocating compressor sources that are routed to a flare as specified in paragraphs (p)(12)(i) through (p)(12)(iii) of this section. (i) Emissions calculations under this paragraph (p) of this section are not required for compressor sources that are routed to a flare. (ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as specified in paragraph (n) of this secti on and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attr ibutable to compressor sources from the flare. Field Code ChangedPage 90 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iii) Report all applicable ac tivity data for compressors with compressor sources routed to flares as specified in § 98.236(p). (q) Equipment leak surveys

. Leak detection and leaker emission factors

. You must use the methods described in §98.234(a) to conduct leak detection(s) of equipment leaks from all component types listed in §98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This paragraph (q) applies to component types in streams with gas content greater than 10 percent CH 4 plus CO 2 by weight. Component types in streams with gas content less than or equal to 10 percent CH 4 plus CO 2 by weight are exempt from the requirements of this paragraph (q) and do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of this paragraph (q) and do not need to be reported. If For industry segments listed in § 98.230(a)(3) through (a)(8), if equipment leaks are detected for sources component types listed in this paragraph (q), then you must calculate equipment leak emissions per component type per reporting facility using Equations W- 30A or W

- 30B 30 of this section for each component type. Use . For the industry segment listed in § 98.230(a)(8), the results from Equation W-30 are used to calculate population emission factors on a meter/regulator run basis using Equation W- 30A for industry segments listed in 98.230(a)(3)

- (a)(7). Use Equation W

- 30B for industry segments listed in 98.230(a)(8). 31 of this section. 

# 

 

###  p x

z z p p s i i p s 

### T EF GHG E 1 , , , , 

### * * (Eq. W- 30A 30 )



#    



   

###  t

n t q x

p q p i i s 

### T EF GHG E 1 1 ,

, 

### * * (Eq. W

- 30B)

Where:Page 91 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. E s, p, i = Annual total volumetric GHG emissions at standard conditions of GHG i from each specific component type “p” (listed in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1)) in standard (“s”) cubic feet, as specified in paragraphs (q)(1) through (q)(8) of this section.

x x p = Total number of each specific component type “p” detected as leaking during annual leak surveys

. EF EF s,p = Leaker emission factor for specific component types listed in Table W-2 through Table W-7 of this subpart. GHG i = For onshore natural gas processi ng facilities, concentration of GHG i , CH 4 or CO 2 , in the total hydrocarbon of the feed natural gas; for onshore natural gas transmission compression and underground natural gas storage, GHG i equals 0.975 for CH 4 and 1.1 ×10 − 2 for CO 2 ; for LNG storage and LNG import and export equipment, GHG i equals 1 for CH 4 and 0 for CO 2 ; and for natural gas distribution, GHG i equals 1 for CH 4 and 1.1 × 10 − 2 CO 2 . T p ,z = The total time the surveyed component , “z”, component type “ p , ”, was found leaking and operational, in hours. If one leak detection survey is conducted in the calendar year , assume the component was leaking for the entire calendar year
. , accounting for time the component was not operational (i.e. not operating under pressure) using engineering estimate based on best available data. If multiple leak detection surveys are conducted in the calendar year , assume that the component found to be leaking has been leaking since the previous survey (if not found leaking in the previous survey) or the beginning of the calendar year (if it was found leaking in the previous survey)

. , accounting for time the component was not operational using engineering estimate based on best available data. For the last leak detection survey in the calendar year, assume that all leaking components continue to leak until the end of the calendar year , accounting for time the component was not operational using engineering estima te based on best available data

. t = Calendar year of reporting.

n = The number of years over which one complete cycle of leak detection is conducted over all the T

- D transfer stations in a natural gas distrib ution facility; 0 < n ≤ 5. For the first (n

- 1) calendar years of reporting the summation in Equation W

- 30B should be for years that the data is available.
T p,q = The total time the component, p, was found leaking and operational, in hours, in year q. If on e leak detection survey is conducted, assume the component was leaking for the entire period n. If multiple leak detection surveys are conducted, assume that the component found to be leaking has been leaking since the previous survey (if not found to be l eaking in the previous survey) or the beginning of the calendar year (if it was found to be leaking in the Formatted: _tabs for equations_lastPage 92 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. previous survey). For the last leak detection survey in the cycle, assume that all leaking components continue to leak until the end of the cycle. (1) You must select to conduct either one leak detection survey in a calendar year or multiple complete leak detection surveys in a calendar year. The number of leak detection surveys selected must be conducted during the calendar year. (2) Calculate GHG both CO 2 and CH 4 mass emissions in carbon dioxide equivalent at standard conditions using calculations in paragraph (v) of this section. (3) Onshore natural gas processing facilities shall must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and noncompressor components in gas service listed in Table W-2 of this subpart for equipment leaks detected from valves, connectors, open ende d lines, pressure relief valves, and meters

. (4) Onshore natural gas transmission compression facilities shall must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non-compressor components in gas service listed in Table W-3 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters

. (5) Underground natural gas storage facilities for storage stations shall must use the appropriate default total hydrocarbon leaker emission factors for storage stations in gas service listed in Table W-4 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters

. (6) LNG storage facilities shall must use the appropriate default methane leaker emission factors for LNG storage components in gas service listed in Table W-5 of this subpart for equipment leaks detected from valves, pump seals, connectors, and other

.Page 93 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (7) LNG import and export facilities shall must use the appropriate default methane leaker emission factors for LNG terminals components in LNG service listed in Table W-6 of this subpart for equipment leaks detected from valves, pump seals, connectors, and other

. (8) Natural gas distribution facilities for above grade transmission

- distribution transfer stations, shall must use the appropriate Equation W-30 of this section and the default methane leaker emission factors for transmission-distribution transfer station components in gas service listed in Table W-7 of this subpart for eq uipment leaks detected from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open ended lines. Leak detection at natural to calculate component emissions from annual equipment leak surveys conducted at above grade transmission-d istribution transfer stations. Natural gas distribution facilities is only are required to perform equipment leak surveys only at above grade stations that qualify as transmission-distribution transfer stations. Below grade transmission-distribution transfer stations and all meteri ng-regulating stations that do not meet the definition of transmission-distribution tr ansfer stations are not required to perform component equipment leak detection surveys under this section. (i) Natural gas distribution faci lities may choose to conduct equipment leak detection surveys at the T

- D all above grade transmission-distribution transfer stations over multiple years, not exceeding a five year period to cover all T

- D above grade transmissiondistribution transfer stations. If the facility chooses to use the multiple year option , then the number of T

- D transmission-distribution transfer stations that are monitored in each year should be approximately equal across all years in the cycle without monitoring the same station twice during the multiple year survey

.Page 94 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) [Reserved] Use Equation W-31 to determine the meter/regulator run population emission factors for each GHG i . The meter/regulator run population emission factors calculated using Equation W-31 must be used in Equation W- 32B of this section to estimate emissions from above grade metering-regulating stations that ar e not transmission-distribu tion transfer stations. As additional survey data beco me available, you must recalcu late the meter/regulator run population emission factors for each GHG i annually according to paragraph (q)(8)(iii) of this section.



#   

     n

y Count

w y w n

y p y i p s
i MR s y MR

T E EF

1 1 , 1 7

1 , , ,

, , , (Eq. W-31)
Where:

EF s,MR,i = Meter/regulator run population emission factor for GHG i based on all surveyed above grade transmission-distri bution transfer stations over “n” years, in standard cubic feet of GHG i per operational hour of all meter/regulator runs. E s,p,i,y = Annual total volumetric emissions at standard conditions of GHG i from component type “p” during year “y” in standard (“s”) cubic feet, as calculated using Equation W-30 of this section.p = Seven component types listed in Table W-7 of this subpart for transmissiondistribution transfer stations. T w,y = The total time the surveyed meter/re gulator run “w” was operational, in hours during survey year “y” using engineering estimate based on best available data. Count MR,y= Count of meter/regulator runs surveyed at above grade transmissiondistribution transfer stations in year “y”. y = Year of data included in emission factor “EF s,MR,i ” according to paragraph (q)(8)(iii) of this section. n = Number of years of data used to calculate emission factor “EF s,MR,i ” according to paragraph (q)(8)(iii) of this section.Page 95 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iii) The emission factor “EF s,MR,i ”, based on annual equipment leak surveys at above grade transmission-distribution transfer stations, must be calculated annually. If the facility has submitted a smaller number of annual reports than the duration of the selected cycle period (up to 5 years), then all available data from the current year and previous years must be used in the emission calculation. After the first cycle is completed, the survey will continue on a rolling basis by including the measurements from the current calendar year and as many of the previous calendar years as are needed to complete the survey cycle. (r) Equipment leaks by population count

. Population count and emission factors

. This paragraph applies to emissions sources listed in §98.232 (c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on streams wi th gas content greater than 10 percent CH 4 plus CO 2 by weight. Emissions sources in st reams with gas content less than or equal to 10 percent CH 4 plus CO 2 by weight are exempt from the requirements of this paragraph (q) and do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of paragraph (r) of this section and do not need to be reported. Calculate You must calculate emissions from all emission sources listed in this paragraph using Equation W- 31 32A of this section

. , except for natural gas distribution facility emission sources listed in § 98.232(i)(3). Natural gas distribution facility emission sources listed in § 98.232(i)(3) must calculate emissions using Equation W-32b and according to paragraph (r)(6) of this section.

e i e s e i e s 

### T GHG EF Count E * * *

, , , 

###  (Eq. W- 32A)

avg w i MR s MR i MR s 

### T EF Count E

, , , , , 

### * *  31 (Eq. W-32B )

Where: Comment [EPA10]: Proposed: Equation Revised and Renumbered.

Comment [EPA11]: Proposed New Equation.Page 96 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. E s, e, i = Annual volumetric GHG emissions at of GHG i from the emission source type in standard conditions from each component type in cubic feet. The emission source type may be a component (e.g. connector, open-ended line, etc.),below grade metering-regulating station, below grade transmissiondistribution transfer station, distri bution main, or distribution service. E s,MR,i = Annual volumetric emissions of GHG i from all meter/regulator runs at above grade metering regulating stations that are not above grade transmission distribution transfer stations, in standard cubic feet. Count s Count e = Total number of this type of the emission source type at the facility. For onshore petroleum and natural gas production facilities , average componentcounts are provided by major equipment piece in Tables W-1B and Table W1C of this subpart. Use average component counts as appropriate for operations in Eastern and Western U.S., according to Table W-1D of this subpart. Underground natural gas storage shall facilities must count the components each component listed for population emission factors in Table W-4

. of this subpart. LNG Storage shall storage facilities must count the number of vapor recovery compressors. LNG import and export shall facilities must count the number of vapor recovery compressors. Natural gas distribution shall facilities must count the meter/regulator runs : (1) the number of distribution services by material type; (2) miles of distribution mains by material type; and (3) number of below grade metering-regulating stations, by pressure type; as described listed in paragraph (r)(6) Table W-7 of this section subpart

. Count MR = Total number of meter/regulator ru ns at above grade metering-regulating stations that are not above grade tran smission-distribution transfer stations. EF s,e = Population emission factor for the specific component emission source type, as listed in Table W

- 1A and Tables W- 3 1A and W-4 through Table W-7 of this subpart. Use appropriate population emission factor for operations in Eastern and Western U.S., according to Table W-1D of this subpart. EF for meter/regulator runs at above grade metering

- regulating stations is determi ned in Equation W

- 32 of this section. EF s,MR,i = Meter/regulator run population emission factor for GHG i based on all surveyed above grade transmission-distri bution transfer stations over “n” years, in standard cubic feet of GHG i per operational hour of all meter/regulator runs., as de termined in Equation W-31. GHG i = For onshore petroleum and natural gas production facilities, concentration of GHG i , CH 4 , or CO 2 , in produced natural gas as defined in paragraph (u)(2) of this section; for onshore natural gas transmission compression and underground natural gas storage, GHG i equals 0.975 for CH 4 and 1.1 × 10 − 2 for CO 2 ; for LNG storage and LNG import and export equipment, GHG i equals 1 for CH 4 and 0 for CO 2 ; and for natural gas distribution, GHG i equals 1 for CH 4 and 1.1 × 10 − 2 CO 2 .Page 97 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. T s T e = Average estimated time that each component emission source type associated with the equipment leak emission was operational in the calendar year, in hours, using engineering estimate based on best available data. T w,avg = Average estimated time that each meter/regulator run was operational in the calendar year, in hours per meter/regulator run, using engineering estimate based on best available data. (1) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (2) Onshore petroleum and natural gas production facilities shall must use the appropriate default whole gas population emission factors listed in Table W-1A of this subpart for equipment leaks from valves, connectors, open ended lines, pressure relief valves, pump, flanges, and other

. Major equipment and components associated with gas wells are considered gas service components in reference to Table W-1A of this subpart and major natural gas equipment in reference to Table W-1B of this subpart. Major equipment and components associated with crude oil wells are considered crude service components in reference to Table W-1A of this subpart and major crude oil equipment in reference to Table W-1C of this subpart. Where facilities conduct EOR operations the emissions factor listed in Table W-1A of this subpart shall be used to estimate all streams of gases, including recycle CO 2 stream. The component count can be determined using either of the methodologies calculation methods described in this paragraph (r)(2). The same methodology calculation method must be used for the entire calendar year. (i) Component Count Method ology 1 . For all onshore petroleum and natural gas production operations in the facility perform the following activities: (A) Count all major equipment listed in Tabl e W-1B and Table W-1C of this subpart. For meters/piping, use one meters/piping per well-pad.Page 98 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) Multiply major equipment counts by the average component counts listed in Table W-1B and W-1C of this subpart for onshore natural gas production and onshore oil production, respectively. Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart. (ii) Component Count Method ology 2 . Count each component individually for the facility. Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart. (3) Underground natural gas storage facilities for storage wellheads shall must use the appropriate default total hydrocarbon population emission factors for storage wellheads in gas service listed in Table W-4 of this subpart for equipment leak from connectors, valves, pressure relief valves, and open ended lines

. (4) LNG storage facilities shall must use the appropriate default methane population emission factors factor for LNG storage compressors in gas service listed in Table W-5 of this subpart for equipment leak from vapor recovery compressors

. (5) LNG import and export facilities shall must use the appropriate default methane population emission factor for LNG terminal compressors in gas service listed in Table W-6 of this subpart for equipment leak from vapor recovery compressors

. (6) Natural gas distribution facilities shall must use the appropriate methane emission factors as described in paragraph (r)(6) of this section. (i) Below grade metering-regulating stations ; , distribution mains ; , and distribution services , shall must use the appropriate default methane population emission factors listed in Table W-7 of this subpart. Below grade T

- D transmission-distribution transfer stations shall must use the emission factor for below grade metering-regulating stations.Page 99 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Emissions from all above grade metering

- regulating stations (including above grade TD transfe r stations) shall be calculated by applying the emission factor calculated in Equation
W

- 32 and the total count of meter/regulator runs at all above grade metering

- regulating stations (inclusive of TD transfer stations) to Equation W

- 31. The facility wide emission factor in Equation W

- 32 will be calculated by using the total volumetric GHG emissions at standard conditions for all equipment leak sources calculated in Equation W

- 30B in paragraph (q)(8) of this section and the count of meter/regulator runs loc ated at above grade transmission

distribution transfer stations that were monito red over the years that c onstitute one complete cycle as per paragraph (q)(8)(i) of this section. A meter on a regulator run is considered one meter/regulator run. Reporters th at do not have above grade T

- D transfer stations shall report a count of above grade metering

- regulating stations only and do not have to comply with § 98.236(c)(16)(xix). Above grade metering-regulating stations (that are not above grade transmission-distribution transfer stations) must use the meter/regulator run population emission factor calculated in Equation W-31. Natural gas distribution facilities that do not have above grade transmission-distribution transfer stations ar e not required to calculate emissions for above grade metering-regulating stations.

Count E EF i s 8760

, 
 (Eq. W

- 32)

Where:

EF = Facility emission factor for a meter/regulator run per component type at above grade metering

- regulating for GHG i in cubic feet per meter/regulator run per hour. E s,i = Annual volumetric GHG i emissions, CO 2 or CH 4 at standard condition from each component type at all above grade TD transfer stations, from Equation W

- 30B.Page 100 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Count = Total number of meter/regulator runs at all TD transfer stations that were monitored over the years that constitute one complete cycle as per (q)(8)(i) of this section. 8760 = Conversion to hourly emissions (s) Offshore petroleum and natural gas production facilities . Report CO 2, CH 4 , and N 2 O emissions for offshore petroleum and natural gas production from all equipment leaks, vented emission, and flare emission source types as iden tified in the data collection and emissions estimation study conducted by BOEMRE in compliance with 30 CFR 250.302 through 304. (1) Offshore production facilities under BOEM RE jurisdiction shall report the same annual emissions as calculated and reported by BOEMRE in data collection and emissions estimation study published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). (i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication year, report the most recent BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). Adjust emissions based on the operating time for the facility relative to the operating time in the most recent BOEMRE published study. (ii) [Reserved] (2) Offshore production facilities that are not under BOEMRE jurisdiction shall must use the most recent monitoring methods and calculation method ol ogie s published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report annual emissions (GOADS). (i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication, you may report the most recent ly reported emissions data submitted to demonstrate compliance with this subpart of part 98, with emissions adjusted based on the operating time for the facility relative to operating time in the previous reporting period.Page 101 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) [Reserved] (3) If BOEMRE discontinues or delays their data collection effort by more than 4 years, then offshore reporters shall once in every 4 years use the most recent BOEMRE data collection and emissions estimation methods to report estimate emissions. These emission estimates would be used to report emissions from the facility sources as required in paragraph (s)(1)(i) of this section

. (4) For either first or subsequent year reportin g, offshore facilities either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle shall must use the most recent BOEMRE data collection and emissions estimation methods published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS) to report emissions

. (t) GHG volumetric emissions using actual conditions . If equation parameters in §98.233 are already at standard conditions, which results in volumetric emissions at standard conditions, then this paragraph does not apply. Calculate vol umetric emissions at standard conditions as specified in paragraphs (t)(1) or (2) of this section, with actual pressure and temperature determined by engineering estimates based on best available data unless otherwise specified. (1) Calculate natural gas volumetric emissions at standard conditions using actual natural gas emission temperature and pressure, and Equation W-33 of this section for conversions of E a,n or conversions of FR a (whether sub-sonic or sonic). 

##    
a s a a s n a n s Z P T P T E E * * 67

. 459 * 67

. 459 *

,

,  

 (Eq. W-33)

Where: Comment [EPA12]: Proposed Revised Equation.Page 102 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. E s,n = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubi c feet, except E s,n equals FR s,p for each well p when calculating either subsonic or sonic flowrates under 98.233(g). E a,n = Natural gas volumetric emissions at actual conditions in cubic feet, except E a,n equals FR a,p for each well p when calculating either subsonic or sonic flowrates under 98.233(g). T s = Temperature at standard conditions (60 °F). T a

= Temperature at actual emission conditions (°F). P s = Absolute pressure at standard conditions (14.7 psia). P a = Absolute pressure at actual conditions (psia). Z a

= Compressibility factor at actual conditions for natural gas. You may use 1 if the temperature is above -10 degrees Fahrenheit and pressure is below 5 atmospheres, or if the compressibility factor at the actual temperature and pressure is 0.98 or greater. (2) Calculate GHG volumetric emissions at standard conditions using actual GHG emissions temperature and pressure, and Equation W-34 of this section. 

##    
a s a a s i a i s Z P T P T E E * * 67

. 459 * 67

. 459 *

,

,  

 (Eq. W-34)

Where:

E s,i = GHG i volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet. E a,i = GHG i volumetric emissions at actual conditions in cubic feet. T s = Temperature at standard conditions (60 °F). T a

= Temperature at actual emission conditions (°F). P s = Absolute pressure at standard conditions (14.7 psia). P a = Absolute pressure at actual conditions (psia). Za = Compressibility factor at actual conditions for GHG i. You may use 1 if the compressibility factor at the actual temperature and pressure is 0.98 or greater. Comment [EPA13]: Proposed Revised Equation.Page 103 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) Reporters using 68 °F for standard temperature may use the ratio 519.67/527.67 to convert volumetric emissions from 68 °F to 60 °F. (u) GHG volumetric emissions

. at standard conditions

. Calculate GHG volumetric emissions at standard conditions as specified in paragraphs (u)(1) and (2) of this section , with mole fraction of GHGs in the natural gas determined by engineering estimate based on best available data unless otherwise specified

. (1) Estimate CH 4 and CO 2 emissions from natural gas emissions using Equation W-35 of this section.
(Eq. W-35)
Where:

E s,i = GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions in cubic feet. E s,n = Natural gas volumetric emissions at standard conditions in cubic feet. M i = Mole fraction of GHG i in the natural gas. (2) For Equation W-35 of this section, the mole fraction, M i , shall be the annual average mole fraction for each sub-basin category or facility, as specified in paragraphs (u)(2)(i) through (vii) of this section. (i) GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities . If you have a continuous gas composition analyzer for produced natural gas, you must use an annual average of these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then you must use an annual average gas composition based on your most recent available anal ysis of the sub-basin category or facility, as applicable to the emission source. i n s i s M E E *

, , Page 104 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the demethanizer or dew point control and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emission s sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities . For onshore natural gas processing plants that solely fractionate a liquid stream, use the GHG mole percent in feed natural gas liquid for all streams. If you have a continuous gas composition analyzer on feed natural gas, you must use these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then annual samples must be taken according to methods set forth in §98.234(b). (iii) GHG mole fraction in transmission pipeline natural gas that passes through the facility for the onshore natural gas transmission compression industry segment . You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas

. or site specific engineering estimates based on best available data. (iv) GHG mole fraction in natural gas stored in the underground natural gas storage industry segment . You may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (v) GHG mole fraction in natural gas stor ed in the LNG stor age industry segment . You
may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering esti mates based on best available data

. (vi) GHG mole fraction in natural gas stored in the LNG import and export industry segment . For export facilities that receive gas from transmission pipelines, you may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data

.Page 105 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities . You may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data

. (v) GHG mass emissions . Calculate GHG mass emissions in carbon dioxide equivalent metric tons by converting the GHG volumetric emis sions at standard conditions into mass emissions using Equation W-36 of this section.

3

, 10 * *   i i s i E Mass  (Eq. W-36) Where:

Mass i = GHG i (either CH 4 , CO 2, or N 2 O) mass emissions in metric tons CO 2 e
. E s,i = GHG i (either CH 4 , CO 2 , or N 2 O) volumetric emissions at standard conditions, in cubic feet. P i = Density of GHG i . Use 0.0526 kg/ft 3 for CO 2 and N 2 O, and 0.0192 kg/ft 3 for CH 4 at 60 °F and 14.7 psia.
GWP = Global warming potential, 1 for CO 2, 2 5 for CH 4 , and 298 for N 2 O

. (w) EOR injection pump blowdown . Calculate CO 2 pump blowdown emissions from each EOR injection pump system as follows: (1) Calculate the total injection pump system volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves. (2) Retain logs of the number of blowdowns per calendar year. (3) Calculate the total annual venting CO 2 emissions from each EOR injection pump system using Equation W-37 of this section:

3 2 2 10 * * * *   CO c v CO GHG R V N Mass (Eq. W-37)

Where:Page 106 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Mass CO2 = Annual EOR injection gas venting pump system emissions in metric tons from blowdowns. N = Number of blowdowns for the equipment EOR injection pump system in the calendar year. V v

= Total volume in cubic feet of blowdown equipment EOR injection pump system chambers (including pipelines, manifolds and vessels) between isolation valves. R c = Density of critical phase EOR injection gas in kg/ft 3 . You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice to determine density of su per critical EOR injection gas. GHG CO2 = Mass fraction of CO 2 in critical phase injection gas. 1 × 10 − 3 = Conversion factor from kilograms to metric tons. (x) EOR hydrocarbon liquids dissolved CO 2 . Calculate CO 2 emissions downstream of the storage tank from dissolved CO 2 in hydrocarbon liquids produced through EOR operations as follows: (1) Determine the amount of CO 2 retained in hydrocarbon liquids after flashing in tankage at STP conditions. Annual samples of hydrocarbon liquids downstream of the storage tank must be taken according to methods set forth in §98.234(b) to determine retention of CO 2 in hydrocarbon liquids immediately downstream of th e storage tank. Use the annual analysis for the calendar year. (2) Estimate emissions using Equation W-38 of this section.

2 * CO hl hl M

ass S V  (Eq. W-38)

Where:

Mass CO2 = Annual CO 2 emissions from CO 2 retained in hydrocarbon liquids produced through EOR operations beyond tankage, in metric tons. S hl = Amount of CO 2 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel, under standard conditions.Page 107 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. V hl = Total volume of hydrocarbon liquids produced at the EOR operations in barrels in the calendar year. (y) [Reserved] (z) Onshore petroleum and natural gas production and natural gas distribution combustion emissions . Calculate CO 2, CH 4 , and N 2 O combustion-related emissions from stationary or portable equipment, except as specified in paragraph (z)(3) and (z)(4) of this section, as follows: (1) If a fuel combusted in the stationary or portable equipment is listed in Table C-1 of subpart C of this part, or is a blend containing one or more fuels listed in Table C-1, calculate emissions according to paragraph (z)(1)(i) of this section . If the fuel combusted is natural gas and is of pipeline quality specification and has a minimum high heat value of 950 Btu per standard cubic foot, use the calculation method ology described in paragraph (z)(1)(i) of this section and you may use the emission factor provided for natural gas as listed in Table C-1. If the fuel is natural gas, and is not pipeline quality or has a high heat value of less than 950 Btu per standard cubic feet, calculate emissions according to paragraph (z)(2) of this section . If the fuel is field gas, process vent gas, or a blend containing fi eld gas or process vent gas, calculate emissions according to paragraph (z)(2) of this section

.(i) For fuels listed in Table C-1 or a blend containing one or more fuels listed in Table C1, calculate CO 2 , CH 4 , and N 2 O emissions according to any Tier listed in subpart C of this part. You must follow all applicable calculation requirements for that tier listed in § 98.33, any monitoring or QA/QC requirements listed for that tier in § 98.34, any missing data procedures specified in 98.35, and any recordkeeping requirements specified in § 98.37.Page 108 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Emissions from fuel combusted in stationary or portable equipment at onshore natural gas and petroleum production facilities and at natural gas distribution facilities will be reported according to the requirements specified in § 98.236(c)(19) and not according to the reporting requirements specified in subpart C of this part. (2) For fuel combustion units that combust fiel d gas, process vent gas, a blend containing field gas or process vent gas, or natural gas that is not of pipeline quality or that has a high heat value of less than 950 Btu per standard cubic f eet, calculate combustion emissions as follows: (i) You may use company records to determine the volume of fuel combusted in the unit during the reporting year. (ii) If you have a continuous gas composition analyzer on fuel to the combustion unit, you must use these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to the unit. If you do not have a continuous gas composition analyzer on gas to the combustion unit, you must use the appropriate gas compositions for each stream of hydrocarbons going to the combustion unit as specified in the applicable paragraph in (u)(2) of this section. (iii) Calculate GHG volumetric emissions at actual conditions using Equations W-39A and W-39B of this section: 

## 

   5

1 2 2 , * * * ) * ( j j j a CO a CO a R Y V Y V E  (Eq. W-39A)


###   4 4 , * 1 * CH a CH a Y V E 
  (Eq. W-39B)

Where:

E a,CO2 = Contribution of annual CO 2 emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions.Page 109 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. V a = Volume of gas sent to combustion unit in actual cubic feet, during the year. Y CO2 = Concentration Mole fraction of CO 2 constituent in gas sent to combustion unit. E a,CH4 = Contribution of annual CH 4 emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions. η = Fraction of gas combusted for portable and stationary equipment determined using engineering estimation. For internal combustion devices, a default of 0.995 can be used. Y

j = Concentration Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes plus) in gas sent to combustion unit. R

j = Number of carbon atoms in the gas hydrocarbon constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus, in gas sent to combustion unit. Y CH4 = Concentration Mole fraction of methane constituent in gas sent to combustion unit. (iv) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (v) Calculate both combustion-related CH 4 and CO 2 mass emissions from volumetric
CH 4 and CO 2 emissions using calculation in paragraph (v) of this section. (vi) Calculate N 2 O mass emissions using Equation W-40 of this section. 

##   EF HHV Fuel Mass O N       3 2 10 1 (Eq. W-40)
Where:

MassN 2 O = Annual N 2 O emissions from the combustion of a particular type of fuel (metric tons CO 2 e ). Fuel = Mass Annual mass or volume of the fuel combusted (mass or volume per year, choose appropriately to be consistent with the units of HHV). HHV = Higher heating value of fuel, mmBtu/unit of fuel (in units consistent with the fuel quantity combusted). For the higher heating value for field gas or process vent gas, use 1.235 × 10 − 3 mmBtu/scf for HHV. Comment [EPA14]: Proposed Revised Equation.Page 110 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. EF = Use 1.0 × 10 − 4 kg N 2 O/mmBtu. 1 × 10 − 3 = Conversion factor from kilograms to metric tons.
GWP = Global warming potential , as listed in Table A

- 1 of subpart A of this part. (3) External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissi ons or include these emissions for threshold determination in §98.231(a). You must report the type and number of each external fuel combustion unit. (4) Internal fuel combustion sources, not compressor-drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr (or the equivalent of 130 horsepower), do not need to report combustion emissions or include these emissions for threshold determination in §98.231(a). You must report the type and number of each internal fuel combustion unit. §98.234 Monitoring and QA/QC requirements

. The GHG emissions data for petroleum and natu ral gas emissions sources must be quality assured as applicable as specified in this sec tion. Offshore petroleum and natural gas production facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 250. (a) You must use any of the methods described as follows in this paragraph to conduct leak detection(s) of equipment leaks and through-valve leakage from all source types listed in § 98.233(k), (o), (p) and (q) that occur during a calendar year , except as provided in paragraph (a)(4) of this section

. (1) Optical gas imaging instrument

. Use an optical gas imaging instrument for equipment leak detection in accordance with 40 CFR part 60, subpart A, § 60.18 of the Alternative work practice for monitoring equipment leaks , § 60.18(i)(1)(i); § 60.18(i)(2)(i) except that the monitoring frequency shall be annual using the detection sensitivity level of 60 grams per hourPage 111 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. as stated in 40 CFR Part 60, subpart A, Table 1: Detection Sensitivity Levels ; § 60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, and § 60.18(i)(2)(iv) and (v); § 60.18(i)(3); § 60.18(i)(4)(i) and (v); including the requireme nts for daily instrument checks and distances, and excluding requirements for video records. Any emissions detected by the optical gas imaging instrument is a leak unless screened with Method 21 (40 CFR part 60, appendix A-7) monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, you must operate the optical gas imaging instrument to image the source types required by this subpart in accordance with the instrument manufacturer’s operating pa rameters. Unless using methods in paragraph (a)(2) of this section, an optical gas imaging instrument must be used for all source types that are inaccessible and cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface. (2) Method 21

. Use the equipment leak detection methods in 40 CFR part 60, appendix A-7, Method 21. If using Method 21 monitoring, if an instrument reading of 10,000 ppm or greater is measured, a leak is detected. Inaccessi ble emissions sources, as defined in 40 CFR part 60, are not exempt from this subpart. Owners or operators must use alternative leak detection devices as described in paragraph (a)(1) or (a)(2) of this section to monitor inaccessible equipment leaks or vented emissions. (3) Infrared laser beam illuminated instrument

. Use an infrared laser beam illuminated instrument for equipment leak detection. Any emissions detected by the infrared laser beam illuminated instrument is a leak unless screen ed with Method 21 monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, you must operate the infrared laser beam illuminated instrument to detect the source type s required by this subpart in accordance with the instrument manufacturer’s operating parameters.Page 112 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (4) [Reserved] (5) Acoustic leak detection device

. Use the acoustic leak detection device to detectthrough-valve leakage. When using the acoustic leak detection device to quantify the throughvalve leakage, you must use the instrument manufacturer’s calculation methods to quantify the through-valve leak. When using the acoustic leak detection device, if a leak of 3.1 scf per hour or greater is calculated, a leak is detected. In addition, you must operate the acoustic leak detection device to monitor the source valves required by this subpart in accordance with the instrument manufacturer’s operating parameters. Acoustic stethoscope type devices designed to detect through valve leakage when put in contact with the valve body and that provide an audible leak signal but do not calculate a leak rate can be used to identify non-leakers with subsequent measurement required to calculate the rate if through-valve leakage is identified. Leaks are reported if a leak rate of 3.1 scf per hour or greater is measured. (b) You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure quantities reported in § 98.233 according to the procedures in § 98.3(i) and the procedures in paragraph (b) of this section. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Associ ation (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (AP I), and the North Americ an Energy Standards Board (NAESB).(c) Use calibrated bags (also known as vent bags) only where the emissions are at nearatmospheric pressures and below the maximum temperature specified by the vent bagPage 113 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. manufacturer such that the bag is safe to handle. The bag opening must be of sufficient size that the entire emission can be tightly encompassed fo r measurement till the bag is completely filled. (1) Hold the bag in place enclosing the emissions source to capture the entire emissions and record the time required for completely fillin g the bag. If the bag infl ates in less than one second, assume one second inflation time. (2) Perform three measurements of the time required to fill the bag, report the emissions as the average of the three readings. (3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t). (4) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in § 98.233(u) and (v). (d) Use a high volume sampler to measure emissions within the capacity of the instrument. (1) A technician following manufacturer instructions shall conduct measurements, including equipment manufacturer operating procedures and measurement method ologie s relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creating backpressure on the source. (2) If the high volume sampler, along with all attachments available from the manufacturer, is not able to capture all the emis sions from the source then use anti-static wraps or other aids to capture all emissions without viol ating operating requirements as provided in the instrument manufacturer’s manual.Page 114 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t). Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in § 98.233(u) and (v). (4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent
CH 4 by using calibrated gas samples and by following manufacturer’s instructions for calibration.(e) Peng Robinson Equation of State means the equation of state defined by Equation W41 of this section:

2 2 2 b bV V a b V RT p

m m m   

   (Eq. W-41)
Where: p = Absolute pressure. R = Universal gas constant. T = Absolute temperature. V m = Molar volume.

a = c c 

### p T

R 2

2 

### 45724

. 0

b = c c p RT 7780

. 0

α = 

#   2 2 1 26992

. 0 54226

. 1 37464

. 0 1                

   

c T T  

Where:

ω = Acentric factor of the species. T c = Critical temperature.Page 115 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. P c = Critical pressure. (f) Special reporting provisions (1) Best available monitoring methods

. EPA will allow owners or operators to use best available monitoring met hods for parameters in § 98.233 Calculating GHG Emissions as specified in paragraphs (f)(2), (f)(3), and (f)(4) of this section. If the reporter anticipates the potential need for best available monitoring for sources for wh ich they need to petition EPA and the situation is unresolved at the time of the d eadline, reporters should submit written notice of this potential situation to EPA by the sp ecified deadline for requests to be consid ered. EPA reserves the right to review best available monitoring method requests submitted after the deadlines specified in this section, and will consider requests which demonstrate unique or unusual circumstances unforeseen at the time of the applicable best available monitoring method deadline. The Administrator reserves the right to request further information in regard to all petition requests. The owner or operator must use the calculation methodologies and equations in § 98.233 Calculating GHG Emissi ons. Best available monitoring methods means any of the following methods specified in paragraph (f)(1) of this section: (i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart. (ii) Supplier data. (iii) En gineering calculations. (iv) Other company records. (2) Best available monitoring methods for well

- related emissions

. During January 1, 2011 through December 31, 2011, owners and operators may use best available monitoring methodsPage 116 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. for any well

- related data that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart. These well

- related sources are: (i) Gas well venting during well completions and workovers with hydraulic fracturing as specified in § 98.233(g). (ii) W ell testing venting and flaring as specified in § 98.233(l). (3) Best available monitoring methods for specified activity data

. During January 1, 2011 through December 31, 2011, owners or operators may use best available monitoring methods for activity dat a as listed below that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart. These sources are: (i) Cumulative hours of venting, days, or times of operation in § 98.233(e), (f), (g), (h), (l), (o), (p), (q), and (r). (ii) Number of blowdowns, completions, workovers, or other events in § 98.233(f), (g), (h), (i), and (w). (iii) Cumulative volume produced, volume input or output, or volume of fuel used in paragraphs § 98.233(d), (e), (j), (k), (l), (m), (n), (x), (y ), and (z). (4) Best available monitoring methods for leak detection and measurement

. During January 1, 2011 through December 31, 2011, owners or operators may use best available monitoring methods for sources requiring leak detection and/or measurement th at cannot reasonably be obtained according to the monitoring and QA/QC requirements of this part. These sources include: (i) Reciprocating compressor rod packing venting in onshore natural gas processing, onshore natural gas transmission compression, under ground natural gas storage, LNG storage,Page 117 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. and LNG import and export equipment as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1). (ii) Centrifugal compressor wet seal oil degassing venting in onshore natural gas processing, onshore natural g as transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2). (iii) Acid gas removal vent stacks in onshore petroleum and natural gas produ ction and onshore natural gas processing as specified in § 98.232(c)(17) and (d)(6). (iv) Equipment leak emissions from valves, connectors, open ended lines, pressure relief valves, block valves, control valves, co mpressor blowdown valves, orifice meters, other meters, regulators, vapor recovery compressors, centrifugal compressor dry seals, and/or other equipment leaks in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import a nd export equipment, and natural gas distribution as specified in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). (v) Condensate (oil and/or water) storage tanks in onshore natural gas transmission compression as specified in § 98.232(e)(3). (5 ) Requests for the use of best available monitoring methods

. (i) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for the sources specified in paragraph (f)(2) of this section. (ii) No request or approval by the Administ rator is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for sources specified in paragraph (f)(3) of this section.Page 118 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iii) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for sources specified in paragraph (f)(4) of this section. (iv) No request or approval by the Administrator is necessary to use best avai lable monitoring methods for data that cannot reasonably be obtained between January 1, 2011 and December 31, 2011 for sources not listed in paragr aph (f)(2), (f)(3), and (f)(4) of this section. (6)

- (7) [Reserved] (8) Requests for extension of the use of b est available monitoring methods beyond 2011 for sources listed in paragraphs (f)(2), (f)(3), (f)(4), and (f)(5)(iv) of this section (i) Timing of request

. EPA does not anticipate a need for best available monitoring methods beyond 2011, but for all repor ting years after 2011, best available monitoring methods will be considered for unique or unusual circ umstances which include data collection methods that do not meet safety regulations, technical inf easibility, or counter to other local, State, or Federal regulations. For use of best available monitoring methods in 2012, an initial notice of intent to request best available monitoring methods must be submitted by December 31, 2011. Any notice of intent submitted prior to the effective date of this rule can not be used to meet this December 31, 2011 deadline; a new notice of in tent must be signed and submitted by the designated representative. In addition to the in itial notification of intent, owners or operators must also submit an extension request containi ng the information specified in 98.234(f)(8)(ii) by March 30, 2012. Any best available monitoring methods request submitted prior to the effective date of this rule cannot be used to meet the March 30, 2012 deadline; a new best available monitoring methods request must be signed and submitted by the designated representative. Owners or operators that submit both a timely noti ce of intent and extension request consistentPage 119 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. with 98.234(f)(8)(ii) can automatically use best available monitoring method through Jun e 30, 2012, for the specific parameters identified in their notification of intent and best available monitoring methods request regardless of whether the best available monitoring methods request is ultimately approved. Owners or operators that submit a n otice of intent but do not follow up with a best available monitoring methods reque st by March 30, 2012 cannot use best available monitoring methods in 2012. For 2012, when an owner or operator has submitted a notice of intent and a subsequent best availab le monitoring method extension request, use of best available monitoring methods will be valid , upon approval by the Administra tor, until the date indicated in the approval or until December 31, 2012, whichever is earlier. For reporting years after 2012, a new request to use best available monitoring methods must be submitted by June 30th of the year prior to the reporting year for which use of best available monitoring methods is sought. (ii) Content of request

. Requests must contain the following informat ion: (A) A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods. (B) For each specific source for which an owner or operator is requesting use of best available monitoring methods, a description of the unique or unusual circumstances, such as data collection methods that do not meet safety regulat ions, technical infeasibility, or specific laws or regulations that are counter to data collection methods that conflict with each specific source. (C) A detailed explanation and supporting documentation of how and when the owner or operator will comply with all of the subpart W reporting requirements for which use of best available monitoring methods are sought. (iii) Approval crite ria

. To obtain approval to use best available monitoring methods after December 31, 2011, the owner or operator must submit a request demonstrating to the Formatted: Level 2Page 120 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Administrator's satisfaction that the owner or operator faces unique or unusual circumstances which i nclude, by way of example and not in limitation, clearly demonstrated data collection methods that do not meet safety regulations, technical infeasibility, or counter to other local, State, or Federal regulations, along with the reasons the owner or operat or cannot otherwise address the unique or unusual circumstances as required to be demonstrated in this paragraph. [Reserved] (g) For the purposes of fulfilling requirement s in 40 CFR 98.233(f) and (g) which require measurements to be taken every other year beginning in the first year of data collection, reporters have the option of taking the first measurement in 2012 to satisfy the requirements for the 2011- 2012 data collection cycle. (h) [Reserved] For well venting for liquids unloading, if a monitoring period other than the full calendar year is used to determine the cumulative amount of time in hours of venting for each well (the
term “T p ” in Equation W-7A and W-7B of § 98.233) or the number of unloading events per well (the term “V p ” in Equations W-8 and W-9 of § 98.233), then the monitoring period must begin before February 1 of the reporting year and must not end before December 1 of the reporting year. The end of one monitoring period must immediately precede the start of the next monitoring period for the next reporting year. All production days must be monitored and all venting accounted for. §98.235 Procedures for estimating missing data. A complete record of all estimated and/or measured parameters used in the GHG emissions calculations is required. If data are lo st or an error occurs during annual emissions estimation or measurements, you must repeat the estimation or measurement activity for thosePage 121 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. sources as soon as possible, including in the s ubsequent calendar year if missing data are not discovered until after December 31 of the year in which data are collected, until valid data for reporting is obtained. Data developed and/or collecte d in a subsequent calendar year to substitute for missing data cannot be used for that subseq uent year's emissions estimation. Where missing data procedures are used for the previous year, at least 30 days must separate emissions estimation or measurements for the previous year and emissions estimation or measurements for the current year of data collection. For missing data which are continuously monitored or measured, (for example flow meters), or for missing temperature or pressure data that are required under § 98.236, the reporter may use best available data for use in emissions determinations. The reporter must record and report the basis for the best available data in these

cases. Except as specified in § 98.233, whenever a value of a parameter is unavailable for a GHG emission calculation required by this subpart (including, but not limited to, if a measuring device malfunctions during unit operation, a required gas sample is not taken, or activity data are not collected), you must follow the procedures specified in paragraphs (a) through (h) of this section, as applicable. (a) If you choose to take quarterly gas samples as allowed in § 98.233(d) in lieu of using a continuous gas analyzer, and there is a missing sample, you must substitute the average value of the last four samples fo r which data are available. (b) If you did not conduct monitoring as specified in §98.233(k) for a transmission storage tank(s), you must assume the vent stack(s ) connected to the transmission storage tank(s) was leaking for the entire calendar year.Page 122 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (c) For stationary and portable combustion sources that use the calculation methods of subpart C of this part, you must use the missing data procedures in subpart C of this part. (d) For each missing value of a parameter that should have been measured using a continuous flow meter, composition analyzer, thermocouple, or pressure gauge, you must substitute the arithmetic average of the quality- assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, you must use the first quality-assured value obtained after the missing data period as the substitute data value. A value is quality-assured according to the procedures specified in §98.234. (e) For the first six months of required data collection, facilities that become newly subject to this subpart W may use best engineer ing estimates for any data that cannot reasonably be measured or obtained according to the requirements of this subpart. (f) For the first six months of required data collection, facilities that are currently subject to this subpart W and that acquire new wells that were not previously subject to this subpart W may use best engineering estimates for any data related to those newly acquired wells that cannot reasonably be measured or obtained according to the requirements of this subpart. (g) For each missing value of any activity data not described in this section, you must substitute data value(s) using the best availabl e estimate(s) of the pa rameter(s), based on all available process data (including, but not limited to, processing rates, operating hours).Page 123 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (h) You must report information for all measur ed and substitute values of a parameter, and the procedures used to substitute an unavailable value of a parameter per the requirements in § 98.236(bb). §98.236 Data reporting requirements

. In addition to the information required by §98.3(c), each annual report must contain reported emissions and related informa tion as specified in this section. (a) Report annual emissions in metric tons of CO 2 e for each GHG separately for each of the industry segments listed in paragraphs (a)(1) through (8) of this section. The annual report must include the information specified in paragraphs (a)(1) through (8) of this section for each applicable industry segment. The annual report must also include annual emissions totals, in metric tons of CO 2 e of each GHG, for each applicable industry segment listed in paragraphs (a)(1) through (a)(8) of this section, and each applicable emission source listed in paragraphs (b) through (z) of this section. (1) Onshore petroleum and natural gas production. For the equipment/activities specified in paragraphs (a)(1)(i) through (a)(1)(xvii) of this section, report the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section. (ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph (c) of this section. (iii) Acid gas removal units. Report the information specified in paragraph (d) of this section. (iv) Dehydrators. Report the information speci fied in paragraph (e) of this section.Page 124 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (v) Liquids unloading. Report th e information specified in pa ragraph (f) of this section. (vi) Completions and workovers with hydraulic fracturing. Report the information specified in paragraph (g) of this section. (vii) Completions and workovers without hydraulic fracturing. Report the information specified in paragraph (h) of this section. (viii) Onshore production storage tanks. Report the information specified in paragraph (j) of this section. (ix) Well testing. Report the information sp ecified in paragraph (l) of this section. (x) Associated natural gas. Report the inform ation specified in paragraph (m) of this section. (xi) Flare stacks. Report the information specified in paragraph (n) of this section. (xii) Centrifugal compressors. Report the inform ation specified in paragraph (o) of this section. (xiii) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (xiv) Equipment leaks by population count. Repo rt the information specified in paragraph (r) of this section. (xv) EOR injection pumps. Report the information specified in paragraph (w) of this section. (xvi) EOR hydrocarbon liquids. Report the inform ation specified in paragraph (x) of this section. (xvii) Combustion equipment. Report the inform ation specified in paragraph (z) of this section.Page 125 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (2) Offshore petroleum and natural gas production. Report the information specified in paragraph (s) of this section. (3) Onshore natural gas processing. For the equipment/activities specified in paragraphs (a)(3)(i) through (a)(3)(vii) of this section, repo rt the information specified in the applicable paragraphs of this section. (i) Acid gas removal units. Report the inform ation specified in paragraph (d) of this section. (ii) Dehydrators. Report the information sp ecified in paragraph (e) of this section. (iii) Blowdown vent stacks. Report the info rmation specified in paragraph (i) of this section. (iv) Flare stacks. Report the information specified in paragraph (n) of this section. (v) Centrifugal compressors. Report the inform ation specified in paragraph (o) of this section. (vi) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (vii) Equipment leak surveys. Report the info rmation specified in paragraph (q) of this section. (4) Onshore natural gas transmission compression. For the equipment/activities specified in paragraphs (a)(4)(i) through (a)(4)(vii) of this section, report the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.Page 126 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section. (iii) Transmission storage tanks. Report the info rmation specified in paragraph (k) of this section. (iv) Flare stacks. Report the information specified in paragraph (n) of this section. (v) Centrifugal compressors. Report the inform ation specified in paragraph (o) of this section. (vi) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (vii) Equipment leak surveys. Report the info rmation specified in paragraph (q) of this section. (5) Underground natural gas storage. For the equipment/activities specified in paragraphs (a)(5)(i) through (a)(5)(vi) of this section, repo rt the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section. (ii) Flare stacks. Report the information specified in paragraph (n) of this section. (iii) Centrifugal compressors. Report the info rmation specified in paragraph (o) of this section. (iv) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (v) Equipment leak surveys. Report the info rmation specified in paragraph (q) of this section.Page 127 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (vi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section. (6) LNG storage. For the equipment/activities specified in paragraphs (a)(6)(i) through (a)(6)(v) of this section, report the information specified in the applicable paragraphs of this section. (i) Flare stacks. Report the information specified in paragraph (n) of this section. (ii) Centrifugal compressors. Report the info rmation specified in paragraph (o) of this section. (iii) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (iv) Equipment leak surveys. Report the information specified in paragraph (q) of this section. (v) Equipment leaks by population count. Report the information specified in paragraph (r) of this section. (7) LNG import and export equipment

. For the equipment/activities specified in paragraphs (a)(7)(i) through (a)(7)(vi) of this section, report the information specified in the applicable paragraphs of this section. (i) Blowdown vent stacks. Report the inform ation specified in paragraph (i) of this section. (ii) Flare stacks. Report the information specified in paragraph (n) of this section. (iii) Centrifugal compressors. Report the info rmation specified in paragraph (o) of this section.Page 128 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iv) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (v) Equipment leak surveys. Report the info rmation specified in paragraph (q) of this section. (vi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section. (8) Natural gas distribution. For the equipment/activities specified in paragraphs (a)(8)(i) through (a)(8)(iii) of this section, report the info rmation specified in the applicable paragraphs of this section. (i) Combustion equipment. Report the information specified in paragraph (z) of this section. (ii) Equipment leak surveys. Report the information specified in paragraph (q) of this section. (iii) Equipment leaks by population count. Report the information specified in paragraph (r) of this section. (b) For offshore petroleum and natural gas production, report emissions of CH 4 , CO 2 , and N 2 O as applicable to the source type (in metric tons CO 2 e per year at standard conditions) individually for all of the emissions source types listed in the most recent BOEMRE study. (c) Report the information listed in this pa ragraph for each applicable source type in metric tons of CO 2 e for each GHG. If a facility operates under more than one industry segment, each piece of equipment should be reported under the unit's respective majority use segment. When a source type listed under this paragraph routes gas to flare, separately report the emissions that were vented directly to the atmosphere without flar ing, and the emissions thatPage 129 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. resulted from flaring the gas. Both the vented and flared emissions will be reported under the respective source type and not under the flare source type. (1) For natural gas pneumatic devices (ref er to Equation W

- 1 of §98.233), report the following: (i) Actual count and estimated count separately of natural gas pneumatic high bleed devices as applicable. (ii) Actual count and estimated count sepa rately of natural gas pneumatic low bleed devices as applicable. (iii) Actual count and estimated count separa tely of natural gas pn eumatic intermittent bleed devices as applicable. (iv) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons
CO 2 e for each gas, for each of the fol lowing pieces of equipment: high bleed pneumatic devices; intermittent bleed pneumatic devices; low bleed pneumatic devices. (2) For natural gas driven pneumatic pumps (refer to Equation W

- 2 of §98.233), report the following, (i) Count of natural gas drive n pneumatic pumps. (ii) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons
CO 2 e for each gas, for all natural gas driven pneumatic pumps combined. (3) For each acid gas removal unit (refer to Equation W

- 3 and Equation W

- 4 o f §98.233), report the following: (i) Total throughput off the acid gas removal unit using a meter or engineering estimate based on process knowledge or best available data in million cubic feet per year.Page 130 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) For Calculation Methodology 1 and Calculation Methodology 2 of §98.233(d), annual average fraction of CO 2 content in the vent from the acid gas removal unit (refer to §98.233(d)(6)). (iii) For Calculation Methodology 3 of §98.233(d), annual average volume fraction of
CO 2 content of natural gas into an d out of the acid gas removal unit (refer to §98.233(d)(7) and (d)(8)). (iv) Report the annual quantity of CO 2 , expressed in metric tons CO 2 e, that was recovered from the AGR unit and transferred outside th e facility, under subpart PP of this part. (v) Rep ort annual CO 2 emissions for the AGR unit, expressed in metric tons CO 2 e. (vi) For the onshore natural gas processing industry segment only, report a unique name or ID number for the AGR unit. (vii) An indication of which calculation methodology was used for the AGR. (4) For dehydrators, report the following: (i) For each Glycol dehydrator with a throughput greater than or equal to 0.4 MMscfd (refer to §98.233(e)(1)), report the following: (A) Glycol dehydrator feed natural gas flow rate in MMscfd, determi ned by engineering estimate based on best available data. (B) Glycol dehydrator absorbent circulation pump type. (C) Whether stripper gas is used in glycol dehydrator. (D) Whether a flash tank separator is used in glycol dehydrator. (E) Type of absorbent. (F) Total time the glycol dehydrator is operating in hours. (G) Temperature, in degrees Fahrenheit and pressure, in psig, of the wet natural gas.Page 131 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (H) Concentration of CH 4 and CO 2 in wet natural gas. (I) What vent gas controls are used (refer to §98.233(e)(3) and (e)(4)). (J) For each glycol dehydrator, report annual CO 2 and CH 4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 e for each gas. (K) For each glycol dehydrator, report annual CO 2 , CH 4 , an d N 2 O emissions that resulted from flaring process gas from the dehydrator, expressed in metric tons CO 2 e for each gas. (L) For the onshore natural gas processing industry segment only, report a unique name or ID number for glycol dehydrator. (ii) For all glycol dehydrators with a throughput less than 0.4 MMscfd (refer to §98.233, Equation W

- 5 of §98.233), report the following: (A) Count of glycol dehydrators. (B) Which vent gas controls are used (refer to §98.233(e)(3) and (e)(4)). (C) Report annual CO 2 an d CH 4 emissions at the facility level that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 e for each gas, combined for all glycol dehydrators with annual average daily throughput of less than 0.4 MMscfd. (D) Report annual CO 2 , CH 4 , and N 2 O emissions at the facility level that resulted from the flaring of process gas, expressed in metric tons CO 2 e for each gas, combined for all glycol dehydrators with annual average daily throughput of less than 0.4 MMscfd. (iii) For absorbent desiccant dehydrators (refer to Equation W

- 6 of §98.233), report the following: (A) Count of desiccant dehydrators. (B) Report annual CO 2 and CH 4 emissions at the facility leve l, expressed in metric tons
CO 2 e for each gas, for all absorbent desic cant dehydrators combined.Page 132 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (5) For well venting for liquids unloading, report the following: (i) For Calculation Methodology 1 (refer to Equation W

- 7 of §98.233), report the following for each tubing diameter group and pressure group combination within eac h sub

- basin category: (A) Count of wells vented to the atmosphere for liquids unloading. (B) Count of plunger lifts. Whether the se lected well from the tubing diameter and pressure group combination had a plunger lift (yes/no). (C) Cumulative number of unl oadings vented to the atmosphere. (D) Average flow rate of the measured well venting in cubic feet per hour (refer to §98.233(f)(1)(i)(A)). (E) Internal casing diameter or internal tubi ng diameter in inches, where applicable, and well depth of each well, i n feet, selected to represent emissions in that tubing size and pressure combination. (F) Casing pressure, in psia, of each well sel ected to represent emissions in that tubing size group and pressure group combination that does not have a plunger lift. (G) Tubing pressure, in psia, of each well selected to represent emissions in a tubing size group and pressure group combination that has a plunger lift. (H) Report annual CO 2 and CH 4 emissions, expressed in metric tons CO 2 e for each gas. (ii) For Calculation Methodologies 2 and 3 (refer to Equation W

- 8 and W

- 9 of §98.233), report the following for each sub

- basin category: (A) Count of wells vented to the atmosphere for liquids unloading. (B) Count of plunger lifts. (C) Cumulative number of unloadings vented t o the atmosphere.Page 133 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (D) Average internal casing diameter, in inches, for all wells, where applicable. (E) Report annual CO 2 and CH 4 emissions, expressed in metric tons CO 2 e for each GHG
gas. (6) For well completions and workovers, report the following for each sub

- basin category: (i) For gas well completions and workovers with hydraulic fracturing by sub

- basin and well type (horizontal or vertical ) combination (refer to Equation W

- 10A and W

- 10B of §98.233), report the following: (A) Total count of completio ns in calendar year. (B) When using Equation W

- 10A, measured flow rate of backflow during well completion in standard cubic feet per hour. (C) Total count of workovers in calendar year that flare gas or vent gas to the atmosphere. (D) When using Equation W

- 10A, measured flow rate of backflow during well workover in standard cubic feet per hour. (E) When using Equation W

- 10A, total number of days of backflow from all wells during completions. (F) When using Equation W

- 10A, total number of days of backflow fr om all wells during workovers. (G) Report number of completions employing purposely designed equipment that separates natural gas from the backflow and the amount of natural gas, in standard cubic feet, recovered using engineering estimate based on best av ailable.Page 134 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (H) Report number of workovers employing purposely designed equipment that separates natural gas from the backflow and the amount of natural gas, in standard cubic feet, recovered using engineering estimate based on best available data. (I) Annual CO 2 and CH 4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 e for each gas. (J) Annual CO 2 , CH 4 , and N 2 O emissions that resulted from flares, expressed in metric
tons CO 2 e for each gas. (ii) For gas well co mpletions and workovers without hydraulic fracturing (refer to Equation W

- 13 of §98.233): (A) Total count of completions in calendar year. (B) Total count of workovers in calendar year that flare gas or vent gas to the atmosphere. (C) Total number of days of gas venting to the atmosphere during backflow for completion. (D) Annual CO 2 and CH 4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 e for each gas. (E) Annual CO 2 , CH 4 , and N 2 O emissions that resulted fr om flares, expressed in metric
tons CO 2 e for each gas. (7) For blowdown vent stack emission source, (refer to Equation W

- 14A and Equation
W

- 14B of §98.233), report the following: (i) For each unique physical volume that is blown down more than once during the calendar year, report the following: (A) Total number of blowdowns for each unique physical volume in the calendar year.Page 135 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) Annual CO 2 and CH 4 emissions, for each unique physical blowdown volume, expressed in metric tons CO 2 e for each gas. (C) A uniqu e name or ID number for the unique physical volume. (ii) For all unique volumes that are blown down once during the calendar year, report the following: (A) Total number of blowdowns for all unique physical volumes in the calendar year. (B) Annual CO 2 and CH 4 emissions from all unique physical volumes as an aggregate per facility, expressed in metric tons CO 2 e for each gas. (8) For gas emitted from produced oil sent to atmospheric tanks: (i) For wellhead gas

- liquid separator with oil throughput greater than or equal to 10 barrels per day, using Calculation Methodology 1 and 2 of §98.233(j), report the following by sub

- basin category, unless otherwise specified: (A) Number of wellhead separators sending oil to atmospheric tanks. (B) Estimated average separato r temperature, in degrees Fahrenheit, and estimated average pressure, in psig. (C) Estimated average sales oil stabilized API gravity, in degrees. (D) Count of hydrocarbon tanks at well pads. (E) Best estimate of count of stock tanks not at well pads recei ving your oil. (F) Total volume of oil from all wellhead separa tors sent to tank(s) in barrels per year. (G) Count of tanks with emissions control m easures, either vapor recovery system or flaring, for tanks at well pads. (H) Best estimate of count of stoc k tanks assumed to have emissions control measures not at well pads, receiving your oil.Page 136 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (I) Range of concentrations of flash gas, CH 4 and CO 2 . (J) Annual CO 2 and CH 4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO 2 e for each gas, for all wellhead gas

- liquid separators or storage tanks using Calculation Methodology 1, and for all wellhead gas

- liquid separators or storage tanks using Calculation Methodology 2 of §98.233(j). (K) Annual CO 2 and CH 4 gas quantities that we re recovered, expressed in metric tons
CO 2 e for each gas, for all wellhead gas

- liquid separators or storage tanks using Calculation Methodology 1, and for all wellhead gas

- liquid separators or storage tanks using Calculation Methodology 2 of §98.233(j). (L ) Annual CO 2, CH 4, and N 2 O emissions that resulted from flaring gas, expressed in metric tons CO 2 e for each gas, for all wellhead gas

- liquid separators or storage tanks using Calculation Methodology 1, and for all wellhead gas

- liquid separators or storage tanks using Calculation Methodology 2 of §98.233(j). (ii) For wells with oil production greater than or equal to 10 barrels per day, using Calculation Methodology 3 and 4 of §98.233(j), report the following by sub

- basin category: (A) Total volume of sales oil from all wells in barrels per year. (B) Total number of wells send ing oil directly to tanks. (C) Total number of wells sending oi l to separators off the well pads. (D) Sales oil API gravity range for wells in (c)(8)(ii)(B) and (c)(8)(ii)(C) of this sec tion, in degrees. (E) Count of hydrocarbon tanks on wellpads. (F) Count of hydrocarbon tanks, both on and off well pads assumed to have emissions control measures: either vapor recovery system or flaring of tank vapors.Page 137 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (G) Annual CO 2 and CH 4 emissions tha t resulted from venting gas to the atmosphere, expressed in metric tons CO 2 e for each gas, at the sub

- basin level for Calculation Methodology 3 or 4 of §98.233(j). (H) Annual CO 2 and CH 4 gas quantities that were recovere d, expressed in metric tons
CO 2 e for each gas, at the sub

- basin level for Calculation Methodology 3 or 4 of §98.233(j). (I) Annual CO 2, CH 4, and N 2 O emissions that resulted from flaring gas, expressed in metric tons CO 2 e for each gas, at the sub

- basin level for Calculation Methodology 3 and 4 of §98.233(j). (iii) For wellhead gas

- liquid separators and wells with throughput less than 10 barrels per day, using Calculation Methodology 5 of §98.233(j) Equation W

- 15 of §98.233, report the following: (A) Number of wellhead separators. (B) Number of wells without wellhead separators. (C) Total volume of oil production in barrels per year. (D) Best estimate of fraction of production sent to tanks with assumed control measures: either vapor recovery system or flaring of tank vapors. (E) Count of hydroc arbon tanks on well pads. (F) Annual CO 2 and CH 4 emissions that resulted from ve nting gas to the atmosphere, expressed in metric tons CO 2 e for each gas, at the sub

- basin level for Calculation Methodology 5 of §98.233(j). (G) Annual CO 2 and CH 4 gas quantities that were recovere d, expressed in metric tons
CO 2 e for each gas, at the sub

- basin level for Calculation Methodology 5 of §98.233(j).Page 138 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (H) Annual CO 2, CH 4, and N 2 O emissions that resulted from flaring gas, expressed in metric tons CO 2 e for ea ch gas, at the sub

- basin level for Calculation Methodology 5 of §98.233(j). (iv) If wellhead separator dump valve is functioning improperly during the calendar year (refer to Equation W

- 16 of §98.233), report the following: (A) Count of wellhead separators that dump valve factor is applied. (B) Annual CO 2 and CH 4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO 2 e for each gas, at the sub

- basin level for improperly functioning dump valves. (9) For transmission tank emis sions identified in §98.233(k) from scrubber dump valves report the following: (i) For each vent stack, report annual CO 2 and CH 4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 e for each gas. (ii) For each transmission storage tank, report annual CO 2 , CH 4 , and N 2 O emissions that resulted from flaring process gas from the transmission storage tank, expressed in metric tons
CO 2 e for each gas. (iii) A unique name or ID number for the vent stack monitored according to 40 CFR 98.233(k). (10) For well testing venting and flaring (refer to Equation W

- 17A or W

- 17B of §98.233), report the following: (i) Number of wells tested per basin in calendar year. (ii) Average gas to oil ratio for each basin. (iii) Average number of days the well is tested in a basin.Page 139 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iv) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons
CO 2 e for each gas, emissions from well testing venting. (v) Report annual CO 2, CH 4, and N 2 O emissions at the facility le vel, expressed in metric
tons CO 2 e for each gas, emissions from well testing flaring. (11) For associated natural gas venting and flaring (refer to Equation W

- 18 of §98.233), report the following for each basin: (i) Number of wells venting or flaring assoc iated natural gas in a calendar year. (ii) Average gas to oil ratio for each basin. (iii) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons
CO 2 e for each gas, emissions from associated natural gas venting. (iv) Report annu al CO 2, CH 4, and N 2 O emissions at the facility level, expressed in metric
tons CO 2 e for each gas, emissions from associated natural gas flaring. (12) For flare stacks (refer to Equation W

- 19, W

- 20, and W

- 21 of §98.233), report the following for each flare: (i) Whether flare has a continuous flow monitor. (ii) Volume of gas sent to flare in cubic feet per year. (iii) Percent of gas sent to un

- lit flare determined by engineering estimate and process knowledge based on best available data and operating records

. (iv) Whether flare has a continuous gas analyzer. (v) Flare combustion efficiency. (vi) Report uncombusted CH 4 emissions, in metric tons CO 2 e (refer to Equation W

- 19 of §98.233).Page 140 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (vii) Report uncombusted CO 2 emissions, in metric tons CO 2 e (refer to Equation W

- 20 of §98.233). (viii) Report combusted CO 2 emissions, in metric tons CO 2 e (refer to Equation W

- 21 of §98.233). (ix) Report N 2 O emissions, in metric tons CO 2 e. (x) For the natural gas processing industry segment, a unique name or ID number for t he flare stack. (xi) In the case that a CEMS is used to measure CO 2 emissions for the flare stack, indicate that a CEMS was used in the annual report and report the combusted CO 2 and uncombusted CO 2 as a combined number. (13) For each centrifugal compresso r: (i) For compressors with wet seals in operational mode (refer to Equations W

- 22 through
W

- 24 of §98.233), report the following for each degassing vent: (A) Number of wet seals connected to the degassing vent. (B) Fraction of vent gas recovered for fuel or sales or flared. (C) Annual throughput in million scf, use an engineering calculation based on best available data. (D) Type of meters used for making measurements. (E) Reporter emission factor for wet seal oil degassing vents in cubic feet per hour (re fer to Equation W

- 24 of §98.233). (F) Total time the compressor is operating in hours. (G) Report seal oil degassing vent emissions for compressors measured and for compressors not measured in metric tons of CO 2 e for each gas.Page 141 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) For wet and dry seal cen trifugal compressors in operating mode, (refer to Equations
W

- 22 through W

- 24 of §98.233), report the following: (A) Total time in hours the compressor is in operating mode. (B) Reporter emission factor for blowdown vents in cubic feet per hour (refer to E quation
W

- 24 of §98.233). (C) Report blowdown vent emissions when in operating mode in metric tons of CO 2 e for each gas. (iii) For wet and dry seal centrifugal compressors in not operating, depressurized mode (refer to Equations W

- 22 through W

- 24 of §98.23 3), report the following: (A) Total time in hours the compressor is in shutdown, depressurized mode. (B) Reporter emission factor for isolation valve emissions in shutdown, depressurized mode in cubic feet per hour (refer to Equation W

- 24 of §98.233). (C) Report the isolation valve leakage emissions in not operating, depressurized mode in metric tons of CO 2 e for each gas. (iv) Report total annual compressor emissions fr om all modes of operation in metric tons of CO 2 e for each gas. (v) For centrifugal compre ssors in onshore petroleum and natural gas production (refer to Equation W

- 25 of §98.233), report the following: (A) Count of compressors. (B) Report annual emissions in metric tons of CO 2 e for each gas (refer to Equation W

- 25 of §98.233) collectively. (14) For reciprocating compressors:Page 142 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) For reciprocating compressors rod packing emissions with or without a vent in operating mode, report the following: (A) Annual throughput in million scf, use an engineering calculation based on best available data. (B) Total time in hours the reciproca ting compressor is in operating mode. (C) Report rod packing emissions for compressors measured and for compressors not measured in metric tons of CO 2 e for each gas. (ii) For reciprocating compressors blowdown vents not manifold to rod packing vents, in operating and standby pressurized mode (refer to Equations W

- 26 through W

- 28 of §98.233), report the following: (A) Total time in hours the compressor is in standby, pressurized mode. (B) Reporter emission factor for blow down vents in cubic feet per hour (refer to §98.233, Equation W

- 28). (C) Report blowdown vent emissions when in operating and standby pressurized modes in metric tons of CO 2 e for each gas. (iii) For reciprocating compressors in not operating, depressurized mode (refer to Equations W

- 26 through W

- 28 of §98.233), report the following: (A) Total time the compressor is in not operating, depressurized mode. (B) Reporter emission factor for isolation valve emissions in not operating, depressurized mode in cubic f eet per hour (refer to Equation W

- 28 of §98.233). (C) Report isolation valve leakage emissions in not operating, depressurized mode in metric tons of CO 2 e for each gas.Page 143 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iv) Report total annual compressor emissions from all modes of operation in metric ton s of CO 2 e for each gas. (v) For reciprocating compressors in onshore petroleum and natural gas production (refer to Equation W

- 29 of §98.233), report the following: (A) Count of compressors. (B) Report annual emissions in metric tons of CO 2 e for each gas c ollectively (refer to Equation W

- 29 of §98.233). (15) For each component type (major equipment type for onshore production) that uses emission factors for estimating emissions (refer to §98.233(q) and (r)) (i) For equipment leaks found in each leak survey (refer to §98.233(q)), report the following: (A) Total count of leaks found in each complete survey listed by date of survey and each component type for which there is a leaker emission factor in Tables W

- 2, W

- 3, W

- 4, W

- 5, W

- 6, and W

- 7 of this subpart. (B) For onshore natural gas processing, range of concentrations of CH 4 and CO 2 (refer to Equation W

- 30A of §98.233). (C) Annual CO 2 and CH 4 emissions in metric tons CO 2 e for each gas (refer to Equation
W

- 30A of §98.233), by component type. (ii) For equipment leaks calculated using population counts and factors (refer to §98.233(r)), report the following: (A) For source categories §98.230(a)(5), (a)(6), and (a)(7), total count for each component type in Tables W

- 4, W

- 5, and W

- 6 of this subpart for which there i s a population emission factor, listed by major heading and component type.Page 144 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) For onshore production (refer to §98.230 paragraph (a)(2)), total count for each type of major equipment in Table W

- 1B and Table W

- 1C of this subpart, by facility. (C) Annual C O 2 and CH 4 emissions, in metric tons CO 2 e for each gas (refer to Equation
W

- 31 of §98.233), by component type. (16) For local distribution companies, report the following: (i) Total number of above grade T

- D transfer stations in the facility. (ii) Number o f years over which all T

- D transfer stations will be monitored at least once. (iii) Number of T

- D stations monitored in calendar year. (iv) Total number of below grade T

- D transfer stations in the facility. (v) Total number of above grade metering

- regulating stations (this count will include above grade T

- D transfer stations) in the facility. (vi) Total number of below grade metering

- regulating stations (this count will include below grade T

- D transfer stations) in the facility. (vii) [Rese rved] (viii) Leak factor for meter/regu lator run developed in Equation W

- 32 of §98.233. (ix) Number of miles of unprotected steel distribution mains. (x) Number of miles of protected steel distribution mains. (xi) Number of miles of plastic distribution mains. (xii) Number of miles of cast iron distribution mains. (xiii) Number of unprotected steel distribution services. (xiv) Number of protected st eel distribution services. (xv) Number of plastic distribution services. (xvi) Number of copper distribution services.Page 145 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (xvii) Annual CO 2 and CH 4 emissions, in metric tons CO 2 e for each gas, from all above grade T

- D transfer stations combined. (xviii) Annual CO 2 and CH 4 emissions, in metric tons CO 2 e for each gas, from all below grade T

- D transfer stations combin ed. (xix) Annual CO 2 and CH 4 emissions, in metric tons CO 2 e for each gas, from all above grade metering

- regulating stations (including T

- D transfer stations) combined. (xx) Annual CO 2 and CH 4 emissions, in metric tons CO 2 e for each gas, from all below grad e metering

- regulating stations (including T

- D transfer stations) combined. (xxi) Annual CO 2 and CH 4 emissions, in metric tons CO 2 e for each gas, from all distribution mains combined. (xxii) Annual CO 2 and CH 4 emissions, in metric tons CO 2 e for each gas, from all distribution services combined. (17) For each EOR injection pump blowdown (refer to Equation W

- 37 of §98.233), report the following: (i) Pump capacity, in barrels per day. (ii) Volume of critical phase gas between isolation valves. (iii) Number of blowdowns per year. (iv) Critical phase EOR injection gas density. (v) For each EOR pump, report annual CO 2 emissions, expressed in metric tons CO 2 e for each gas. (18) For EOR hydrocarbon liquids dissolved CO 2 for each sub

- basin category (r efer to Equation W

- 38 of §98.233), report the following: (i) Volume of crude oil produced in barrels per year.Page 146 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Amount of CO 2 retained in hydrocarbon liquids in metric tons per barrel, under standard conditions. (iii) Report annual CO 2 e missions at the sub

- basin level, expressed in metric tons CO 2 e. (19) For onshore petroleum and natural gas production and natural gas distribution combustion emissions, report the following: (i) Cumulative number of external fuel combustion units with a rated heat capaci ty equal to or less than 5 mmBtu/hr, by type of unit. (ii) Cumulative number of external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by type of unit. (iii) Report annual CO 2 , CH 4 , and N 2 O emissions from external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, expressed in metric tons CO 2 e for each gas, by type of unit. (iv) Cumulative volume of fuel combusted in external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by fuel typ e. (v) Cumulative number of internal fuel combustion units, not compressor

- drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr or 130 horsepower, by type of unit. (vi) Report annual CO 2 , CH 4 , and N 2 O emissions from internal combustion unit s greater than 1mmBtu/hr, expressed in metric tons CO 2 e for each gas, by type of unit. (vii) Cumulative volume of fuel combusted in internal combustion units with a rated heat capacity larger than 1 mmBtu/hr or 130 horsepower, by fuel type. (d) Report annu al throughput as determined by engineering estimate based on best available data for each industry segment listed in paragraphs (a)(1) through (a)(8) of this section.Page 147 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (e) For onshore petroleum and natural gas production, report the best available estimate of API gravity, best available estimate of gas to oil ratio, and best available estimate of average low pressure separator pressure for each oil sub

- basin category. (b) Natural gas pneumatic devices. You must indicate whether the facility contains the following types of equipment: continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, and inte rmittent bleed natural gas pneumatic devices. If the facility contains any continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, or intermittent bleed natural gas pneumatic devices, then you must report the information specified in paragraphs (b)(1) through (b)(4) of this section. (1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) and (b)(1)(ii) of this section. (i) The total number of devices, determined according to §98.233(a)(1) and (a)(2). (ii) If the reported value in paragraph (b)(1) (i) of this section is an estimated value determined according to §98.233(a)(2), then yo u must report the information specified in paragraphs (b)(1)(ii)(A) through (b)(1)(ii)(C) of this section. (A) The number of devices reported in paragraph (b)(1)(i) of this section that are counted. (B) The number of devices reported in paragraph (b)(1)(i) of this section that are estimated (not counted). (C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting. (2) Estimated average number of hours in the calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) of this section were operating in the calendar year (“Tt” in Equation W-1 of this subpart).Page 148 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) Annual CO 2 emissions, in metric tons CO 2 , for the natural gas pneumatic devices combined, calculated using Equation W-1 of this subpart and § 98.233(a)(4), and reported in paragraph (b)(1)(i) of this section. (4) Annual CH 4 emissions, in metric tons CH 4 , for the natural gas pneumatic devices combined, calculated using Equation W-1 of this subpart and § 98.233(a)(4), and reported in paragraph (b)(1)(i) of this section. (c) Natural gas driv en pneumatic pumps . You must indicate whether the facility has any natural gas driven pneumatic pumps. If the facility contains any natural gas driven pneumatic pumps, then you must report the information specified in paragraphs (c)(1) through (c)(4) of this section. (1) Count of natural gas driven pneumatic pumps. (2) Average estimated number of hours in the calendar year the pumps were operational (“T” in Equation W-2 of this subpart). (3) Annual CO 2 emissions, in metric tons CO 2 , for all natural gas driven pneumatic pumps combined, calculated according to §98.233(c)(1) and (c)(2). (4) Annual CH 4 emissions, in metric tons CH 4 , for all natural gas driven pneumatic pumps combined, calculated according to §98.233(c)(1) and (c)(2). (d) Acid gas removal units . You must indicate whether your facility has any acid gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant. If your facility contains any acid gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant, then you must report the information specified in paragraphs (d)(1) and (d)(2) of this section.Page 149 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (1) You must report the information specified in paragraphs (d)(1)(i) through (d)(1)(vi) of this section for each acid gas removal unit. (i) A unique name or ID number for the acid gas removal unit. For the onshore petroleum and natural gas production industry segment, a different name or ID may be used for a single acid gas removal unit for each location it operates at in a given year. (ii) Total feed rate entering the acid gas removal unit, using a meter or engineering estimate based on process knowledge or best available data, in million cubic feet per year. (iii) The calculation method used to calculate CO 2 emissions from the acid gas removal unit, as specified in § 98.233(d). (iv) Whether any CO 2 emissions from the acid gas removal unit are recovered and transferred outside the facility, as specified in § 98.233(d)(11). If any CO 2 emissions from the acid gas removal unit were recovered and transferred outside the facility, then you must report the annual quantity of CO 2 , in metric tons CO 2, that was recovered and transferred outside the facility. (v) Annual CO 2 emissions, in metric tons CO 2 , from the acid gas removal unit, calculated using any one of the calculation methods specified in § 98.233(d) and as specified in § 98.233(d)(10) and (11). (vi) Sub-basin ID (for the onshore petroleum and natural gas production industry segment only). (2) You must report information specified in paragraphs (d)(2)(i) through (d)(2)(iii) of this section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, for each acid gas removal unit.Page 150 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) If you used Calculation Method 1 or Calc ulation Method 2 as specified in § 98.233(d) to calculate CO 2 emissions from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(i)(A) and (d)(2)(i)(B) of this section. (A) Annual average volumetric fraction of CO 2 in the vent gas exiting the acid gas removal unit. (B) Annual volume of gas vented from the acid gas removal unit, in cubic feet. (ii) If you used Calculation Method 3 as specified in § 98.233(d) to calculate CO 2 emissions from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(ii)(A) through (d )(2)(ii)(D) of this section. (A) Which equation was used; Equation W-4A or W-4B. (B) Annual average volumetric fraction of CO 2 in the natural gas flowing out of the acid gas removal unit, as specified in Equation W-4A or Equation W-4B of this subpart. (C) Annual average volumetric fraction of CO 2 content in natural gas flowing into the acid gas removal unit, as specified in Equation W-4A or Equation W-4B of this subpart. (D) The natural gas flow rate used, as specified in Equation W-4A of this subpart, reported as either total annual volume of natural gas flow into the acid gas removal unit in cubic feet at actual conditions; or total annual volume of natural gas flow out of the acid gas removal unit, as specified in Equation W-4B of this subpart, in cubic feet at actual conditions,. (iii) If you used Calculation Method 4 as specified in § 98.233(d) to calculate CO 2 emissions from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(iii)(A) through (d)(2)(iii)(L) of this section, as applicable to the simulation software package used. (A) The name of the simulation software package used.Page 151 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) Natural gas feed temperature, in degrees Fahrenheit. (C) Natural gas feed pressure, in pounds per square inch. (D) Natural gas flow rate, in standard cubic feet per minute. (E) Acid gas content of the feed natural gas, in mole percent. (F) Acid gas content of the outlet natural gas, in mole percent. (G) Unit operating hours, excluding downtime for maintenance or standby, in hours per
year. (H) Exit temperature of the natural gas, in degrees Fahrenheit. (I) Solvent pressure, in pounds per square inch. (J) Solvent temperature, in degrees Fahrenheit. (K) Solvent circulation rate , in gallons per minute. (L) Solvent weight, in pounds per gallon. (e) Dehydrator s. You must indicate whether your facility contains any of the following equipment: absorbent dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 million standard cubic feet per day, glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day, and dehydrators that use desiccant. If your facility contains any of the equipment listed in this paragraph (e), then you must report the applicable information in paragraphs (e)(1) through (e)(3). (1) For each absorbent dehydrator that has an annual average daily natural gas throughput greater than or equal to 0.4 million standard cubic feet per day (as specified in § 98.233(e)(1)), you must report the information specified in pa ragraphs (e)(1)(i) through (e)(1)(xviii) of this section for the dehydrator.Page 152 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) A unique name or ID number for the dehydrator. For the onshore petroleum and natural gas production industry segment, a different name or ID may be used for a single dehydrator for each location it operates at in a given year. (ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, determined by engineering estimate based on best available data. (iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet. (iv) Dehydrator outlet natural gas water c ontent, in pounds per million standard cubic feet. (v) Dehydrator absorbent circulation pump type (e.g., natural gas pneumatic, air pneumatic, or electric). (vi) Dehydrator absorbent circula tion rate, in gallons per minute. (vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene glycol (DEG), or ethylene glycol (EG)). (viii) Whether stripper gas is used in dehydrator. (ix) Whether a flash tank separator is used in dehydrator. (x) Total time the dehydrator is operating, in hours. (xi) Temperature of the wet natural gas, in degrees Fahrenheit. (xii) Pressure of the wet natural gas, in pounds per square inch gauge. (xiii) Mole fraction of CH 4 in wet natural gas. (xiv) Mole fraction of CO 2 in wet natural gas. (xv) Whether any dehydrator emissions are vented to a vapor recovery device. (xvi) Whether any dehydrator emissions are ve nted to a flare or regenerator firebox/fire tubes. If any emissions are vented to a flare or regenerator firebox/fire tubes, report thePage 153 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. information specified in paragraphs (e)(1)(xvi)(A) through (e)(1)(xvi)(C) of this section for these emissions from the dehydrator. (A) Annual CO 2 emissions, in metric tons CO 2 , for the dehydrator, calculated according to § 98.233(e)(6). (B) Annual CH 4 emissions, in metric tons CH 4 , for the dehydrator, calculated according to § 98.233(e)(6). (C) Annual N 2 O emissions, in metric tons N 2 O, for the dehydrator, calculated according to § 98.233(e)(6). (xvii) Whether any dehydrator emissions are vented to the atmosphere without being routed to a flare or regenerator firebox/fire tubes. If any emissions are not routed to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(1)(xvii)(A) and (e)(1)(xvii)(B) of this s ection for those emissions from the dehydrator. (A) Annual CO 2 emissions, in metric tons CO 2 , for the dehydrator when not venting to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and (e)(5). (B) Annual CH 4 emissions, in metric tons CH 4 , for the dehydrator when not venting to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and (e)(5). (xviii) Sub-basin ID (for the onshore petroleum and natural gas production industry segment only). (2) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day (as specified in § 98.233(e)(2)), you must report the information specified in paragraphs (e)(2)(i) through (e)(2)(v) of this section for the entire facility. (i) The total number of dehydrators at the facility.Page 154 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Whether any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a vapor recovery device. If any dehydrators report ed in paragraph (e)(2)(i) of this section were vented to a vapor recovery device, then you must report the total number of dehydrators at the facility that vented to a vapor recovery device. (iii) Whether any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a control device other than a vapor recovery devi ce or a flare or regenerator firebox/fire tubes. If any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes, then you must specify the type of control device and the number of dehydrators at the facility that were vented to each type of control device. (iv) Whether any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a flare or regenerator firebox/fire tubes. If any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(2)(iv)(A) through (e)(2)(iv)(D) of this section. (A) The total number of dehydrators venting to a flare or regenerator firebox/fire tubes. (B) Annual CO 2 emissions, in metric tons CO 2 , for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(6). (C) Annual CH 4 emissions, in metric tons CH 4 , for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(6). (D) Annual N 2 O emissions, in metric tons N 2 O, for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(6).Page 155 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (v) For dehydrators reported in paragraph (e)(2)(i) of this section that were not vented to a flare or regenerator firebox/fire tubes, repo rt the information specified in paragraphs (e)(2)(v)(A) and (e)(2)(v)(B) of this section. (A) Annual CO 2 emissions in metric tons CO 2 , for emissions from all dehydrators reported in paragraph (e)(2)(i) of this section th at were not vented to a flare or regenerator firebox/fire tubes, calculated according to § 98.2 33(e)(2), (e)(4), and (e)(5), where emissions are added together for all such dehydrators. (B) Annual CH 4 emissions in metric tons CO 2 , for emissions from all dehydrators reported in paragraph (e)(2)(i) of this section th at were not vented to a flare or regenerator firebox/fire tubes, calculated according to § 98.2 33(e)(2), (e)(4), and (e)(5), where emissions are added together for all such dehydrators. (3) For dehydrators that use desiccant (as specified in § 98.233(e)(3)), you must report the information specified in paragr aphs (e)(3)(i) through (e)(3)(iii) of this section for the entire facility. (i) The same information specified in paragraphs (e)(2)(i) through (e)(2)(iv) of this section for glycol dehydrators, and report the information under this paragraph for dehydrators that use desiccant. (ii) Annual CO 2 emissions, in metric tons CO 2 , for emissions from all desiccant dehydrators reported under paragraph (e)(3)(i) of this section that are not venting to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(3), (e)(4), and (e)(5), and summing for all such dehydrators. (iii) Annual CH 4 emissions, in metric tons CH 4 , for emissions from all desiccant dehydrators reported in paragraph (e)(3)(i) of this section that are not venting to a flare orPage 156 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. regenerator firebox/fire tubes, calculated according to § 98.233(e)(3), (e)(4), and (e)(5), and summing for all such dehydrators. (f) Liquids unloading . You must indicate whether well venting for liquids unloading occurs at your facility, and if so, which met hods (as specified in § 98.233(f)) were used to calculate emissions. If your facility perform s well venting for liquids unloading and uses Calculation Method 1, then you must report the in formation specified in paragraph (f)(1) of this section. If the facility performs liquids unloadin g and uses Calculation Me thod 2 or 3, then you must report the information specified in paragraph (f)(2) of this section. (1) For each sub-basin and well tubing diameter and pressure grouping for which you used Calculation Method 1 to calculate natural gas emissions from well venting for liquids unloading, report the information specified in pa ragraphs (f)(1)(i) through (f)(1)(xii) of this section. Report information separately for wells w ith plunger lifts and wells without plunger lifts. (i) Sub-basin ID. (ii) Well tubing diameter and pressure group ID. (iii) Plunger lift indicator. (iv) Count of wells vented to the atmosphere for the sub-basin/well tubing diameter and pressure grouping. (v) Percentage of wells for which the monitoring period used to determine the cumulative amount of time venting was not the full calendar year. (vi) Cumulative amount of time wells were vented (sum of “T p ” from Equation W-7A or W-7B of this subpart), in hours. (vii) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all wells in the sub-basin/well tubing diameter and pressure grouping.Page 157 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (viii) Annual natural gas emissions, in sta ndard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(1). (ix) Annual CO 2 emissions, in metric tons CO 2 , from well venting for liquids unloading, calculated according to § 98.233(f)(1) and § 98.233(f)(4). (x) Annual CH 4 emissions, in metric tons CH 4 , from well venting for liquids unloading, calculated according to § 98.233(f)(1) and § 98.233(f)(4). (xi) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xi)(A) through (f)(1)(xi)(E) of this section for each individual well not using a plunger lift that was tested during the year. (A) API number of tested well. (B) Casing pressure, in pounds per square inch absolute. (C) Internal casing diameter, in inches. (D) Measured depth of the well, in feet. (E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour. (xii) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)( 1)(xii)(A) through (f)(1)(xii)(E) of this section for each individual well using a plunger lift that was tested during the year

. (A) The API well number. (B) The tubing pressure, in pounds per square inch absolute. (C) The internal tubing diameter, in inches. (D) Measured depth of the well, in feet.Page 158 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour. (2) For each sub-basin for which you used Calculation Method 2 or 3 (as specified in § 93.233(f)) to calculate natural gas emissions from well venting for liquids unloading, you must report the information in (f)(2)(i) through (f)(2)(x) of this section. Report information separately for each calculation method. (i) Sub-basin ID. (ii) Calculation method. (iii) Plunger lift indicator. (iv) Number of wells vented to the atmosphere. (v) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all wells. (vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated accordin g to § 98.233(f)(2) or § 98.233(f)(3), as applicable. (vii) Annual CO 2 emissions, in metric tons CO 2 , from well venting for liquids unloading, calculated according to § 98.233(f)(2) or § 98.233(f)(3), as applicable, and § 98.233(f)(4). (viii) Annual CH 4 emissions, in metric tons CH 4 , from well venting for liquids unloading, calculated according to § 98.233(f) (2) or § 98.233(f)(3), as applicable, and § 98.233(f)(4). (ix) For wells without plunger lifts, the av erage internal casing diameter, in inches. (x) For wells with plunger lifts, the average internal tubing diameter, in inches. (g) Completions and workovers with hydraulic fracturing . You must indicate whether your facility had any gas well completions or workovers with hydraulic fracturing during the calendar year. If your facility had gas well comple tions or workovers with hydraulic fracturingPage 159 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. during the calendar year, then you must report information specified in paragraphs (g)(1) through (g)(10) of this section, for each sub-basin and well type combination. Report information separately for completions and workovers. (1) Sub-basin ID. (2) Well type . (3) Number of completions or workovers in the category. (4) Calculation method used. (5) If you used Equation W-10A to calculate annual volumetric total gas emissions, then you must report the information specified in para graphs (g)(5)(i) and (g)(5)(ii) of this section. (i) Cumulative backflow time, in hours, for each sub-basin (“T p ” in Equation W-10A). (ii) Measured flowback rate, in standard cubic feet per hour, for each sub-basin (“FR s,p ” in Equation W-12A). (6) If you used Equation W-10B to calculate annual volumetric total gas emissions for completions that vent gas to the atmosphere, then you must report the vented natural gas volume, in standard cubic feet, for each well in the sub-basin (“FV s,p ” in Equation W-10B). (7) Annual gas emissions, in standard cubic feet (“E s,n ” in Equation W-10A or W-10B). (8) Annual CO 2 emissions, in metric tons CO 2 . (9) Annual CH 4 emissions, in metric tons CH 4 . (10) If the well emissions were vented to a flare, then you must report the total N 2 O emissions, in metric tons N 2 O. (h) Completions and workovers without hydraulic fracturing . You must indicate whether the facility had any gas well completions without hydraulic fracturing or any gas well workovers without hydraulic fracturing, and if the activities occurred with or without flaring. If the facilityPage 160 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. had gas well completions or workovers without hydraulic fracturing, then you must report the information specified in paragraphs (h)(1) through (h)(4) of this section, as applicable. (1) For each sub-basin with gas well completions without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(1)(i) through (h)(1)(vi) of this section. (i) Sub-basin ID. (ii) Number of well completions that vented gas directly to the atmosphere without flaring. (iii) Total number of hours that gas vented directly to the atmosphere during backflow for all completions in the sub-basin category (the sum of all “T p ” for completions that vented to the atmosphere as used in Equation W-13B). (iv) Average daily gas production rate for all completions without hydraulic fracturing in the sub-basin without flaring, in standard cubic feet per hour (average of all “V p ” used in Equation W-13B). (v) Annual CO 2 emissions, in metric tons CO 2 , that resulted from completions venting gas directly to the atmosphere (“E s,p ” from Equation W-13B for completions that vented directly to the atmosphere, converted to mass emissions according to §98.233(h)(1)). (vi) Annual CH 4 emissions, in metric tons CH 4 , that resulted from completions venting gas directly to the atmosphere (“E s,p ” from Equation W-13B for completions that vented directly to the atmosphere, converted to mass emissions according to §98.233(h)(1)). (2) For each sub-basin with gas well completions without hydraulic fracturing and with flaring, report the information specified in paragrap hs (h)(2)(i) through (h)(2)(vii) of this section. (i) Sub-basin ID. Formatted: Not Superscript/ SubscriptPage 161 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Number of well comple tions that flared gas. (iii) Total number of hours that gas vented to a flare during backflow for all completions in the sub-basin category (the sum of all “T p ” for completions that vented to a flare from Equation W-13B). (iv) Average daily gas production rate for all completions without hydraulic fracturing in the sub-basin with flaring, in standard cubic feet per hour (the average of all “V p ” from Equation W-13B). (v) Annual CO 2 emissions, in metric tons CO 2 , that resulted from completions that flared gas calculated according to §98.233(h)(2). (vi) Annual CH 4 emissions, in metric tons CH 4 , that resulted from completions that flared gas calculated according to §98.233(h)(2). (vii) Annual N 2 O emissions, in metric tons N 2 O, that resulted from completions that flared gas calculated according to §98.233(h)(2). (3) For each sub-basin with gas well workovers without hydraulic fracturing and without flaring, report the information specified in paragrap hs (h)(3)(i) through (h)(3)(iv) of this section. (i) Sub-basin ID. (ii) Number of workovers that vented gas to the atmosphere without flaring. (iii) Annual CO 2 emissions, in metric tons CO 2 per year, that resulted from workovers venting gas directly to the atmosphere (“E s,wo ” in Equation W-13A for workovers that vented directly to the atmosphere, converted to ma ss emissions as specified in §98.233(h)(1)). (iv) Annual CH 4 emissions, in metric tons CH 4 per year, that resulted from workovers venting gas directly to the atmosphere (“E s,wo ” in Equation W-13A for workovers that vented directly to the atmosphere, converted to ma ss emissions as specified in §98.233(h)(1)).Page 162 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (4) For each sub-basin with gas well workovers without hydraulic fracturing and with flaring, report the information specified in paragr aphs (h)(4)(i) through (h)(4)(v) of this section. (i) Sub-basin ID. (ii) Number of workovers that flared gas. (iii) Annual CO 2 emissions, in metric tons CO 2 per year, that resulted from workovers that flared gas calculated as specified in §98.233(h)(2). (iv) Annual CH 4 emissions, in metric tons CH 4 per year, that resulted from workovers that flared gas, calculated as specified in §98.233(h)(2). (v) Annual N 2 O emissions, in metric tons N 2 O per year, that resulted from workovers that flared gas calculated as specified in §98.233(h)(2). (i) Blowdown vent stacks . You must indicate whether your facility has blowdown vent stacks. If your facility has blowdown vent stacks, then you must report whether emissions were calculated by equipment type or by using flow meters. If you calculated emissions by equipment type, then you must report the information specified in paragraph (i)(1) of this section. If you calculated emissions using flow meters, then you must report the information specified in paragraph (i)(2) of this section. (1) Report by equipment type . If you calculated emissions from blowdown vent stacks by equipment type, then you must report the equipment types and the information specified in paragraphs (i)(1)(i) through (i)(1)(iii) of this section for each equipment type. If a blowdown event resulted in emissions from mu ltiple equipment types, then y ou must report the information in paragraphs (i)(1)(i) through (i)(1)(iii) of this section for the equipment type that represented the largest portion of the emissions for the blowdown event.Page 163 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Total number of blowdowns in the calendar year for the equipment type (the sum of equation variable “N” from Equation W-14A or Equation W-14B of this subpart, for all unique physical volumes for the equipment type). (ii) Annual CO 2 emissions for the equipment type, in metric tons CO 2 , calculated according to § 98.233(i)(2)(iii). (iii) Annual CH 4 emissions for the equipmen t type, in metric tons CH 4 , calculated according to §98.233(i)(2)(iii). (2) Report by flow meter . If you elect to calculate emissions from blowdown vent stacks by using a flow meter according to §98.233(i)(3), then you must report the information specified in paragraphs (i)(2)(i) and (i)(2)(ii) of this section for the facility. (i) Annual CO 2 emissions from all blowdown vent stacks at the facility, in metric tons
CO 2 (the sum of all CO 2 mass emission values calculated according to § 98.233(i)(3), for all flow meters). (ii) Annual CH 4 emissions from all blowdown vent stacks at the facility, in metric tons
CH 4 , (the sum of all CH 4 mass emission values calculated according to § 98.233(i)(3), for all flow meters). (j) Onshore production storage tanks . You must indicate whether your facility sends produced oil to atmospheric tanks. If your facility sends produced oil to atmospheric tanks, then you must indicate which Calculation Method(s) you used to calculate GHG emissions, and you must report the information specified in paragraphs (j)(1) and (j)(2) of this section as applicable. If any atmospheric tanks were observed to have malfunctioning dump valves during the calendar year, then you must indicate that dump valves were malfunctioning and you must report the information specified in paragrap h (j)(3) of this section.Page 164 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (1) If you used Calculation Method 1 or Calculation Method 2 to calculate GHG emissions, then you must report the information specified in paragraphs (j)(1)(i) through (j)(1)(xiv) of this section for each sub-basin and by calculation method. (i) Sub-basin ID. (ii) Calculation method used, and name of the software package used if using Calculation Method 1. (iii) The total annual gas-liquid separator oil volume that is sent to applicable onshore production storage tanks, in barrels. (iv) The average gas-liquid separator temperature, in degrees. (v) The average gas-liquid separator pressure, in pounds per square inch gauge. (vi) The average sales oil or stabilized oil API gravity, in degrees. (vii) The minimum and maximum concentration (mole fraction) of CO 2 in flash gas from onshore production storage tanks. (viii) The minimum and maximum concentration (mole fraction) of CH 4 in flash gas from onshore production storage tanks. (ix) The number of wells sending oil to gas- liquid separators or directly to atmospheric tanks. (x) The number of atmospheric tanks. (xi) An estimate of the number of atmospheric tanks, not on well-pads, receiving your oil. (xii) If any emissions from the atmospheric tanks at your facility were controlled with vapor recovery systems, then you must report the information specified in paragraphs (j)(1)(xii)(A) through (j)(1)(xii)(E) of this section.Page 165 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (A) The number of atmospheric tanks that control emissions with vapor recovery systems. (B) Total CO 2 mass, in metric tons CO 2 , that was recovered during the calendar year using a vapor recovery system. (C) Total CH 4 mass, in metric tons CH 4 , that was recovered during the calendar year using a vapor recovery system. (D) Annual CO 2 emissions, in metric tons CO 2 , from atmospheric tanks equipped with vapor recovery systems. (E) Annual CH 4 emissions, in metric tons CH 4 , from atmospheric tanks equipped with vapor recovery systems. (xiii) If any atmospheric tanks at your faci lity vented gas directly to the atmosphere without using a vapor recovery system or without flaring, then you must report the information specified in paragraphs (j)(1)(xiii)(A) through (j)(1)(xiii)(C) of this section. (A) The number of atmospheric tanks that vented gas directly to the atmosphere without using a vapor recovery system or without flaring. (B) Annual CO 2 emissions, in metric tons CO 2 , that resulted from venting gas directly to the atmosphere

. (C) Annual CH 4 emissions, in metric tons CH 4 , that resulted from venting gas directly to the atmosphere. (xiv) If you controlled emissions from any atmospheric tanks at your facility with one or more flares, then you must report the information specified in paragraphs (j)(1)(xiv)(A) through (j)(1)(xiv)(D) of this section. (A) The number of atmospheric tanks that controlled emissions with flares.Page 166 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) Annual CO 2 emissions, in metric tons CO 2 , from atmospheric tanks that controlled emissions with one or more flares. (C) Annual CH 4 emissions, in metric tons CH 4 , from atmospheric tanks that controlled emissions with one or more flares. (D) Annual N 2 O emissions, in metric tons N 2 O, from atmospheric tanks that controlled emissions with one or more flares. (2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the information specified in paragraph (j)( 2)(i) through (j)(2)(iii) of this paragraph. (i) Report the information specified in paragrap hs (j)(2)(i)(A) through (j)(2)(i)(F) of this section, at the basin level, for atmospheric tanks where emissions were calculated using Calculation Method 3. (A) The total annual oil throughput that is sent to all atmospheric tanks in the basin, in barrels. (B) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) sent to atmospheric tanks in the basin that controlled emissions with flares. (C) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) sent to atmospheric tanks in the basin that controlled emissions with vapor recovery systems. (D) The number of atmospheric tanks in the basin. (E) The number of wells with gas-liquid separators (“Count” from Equation W-15 of this subpart)in the basin. (F) The number of wells without gas-liquid separators (“Count” from Equation W-15 of this subpart)in the basin.Page 167 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Report the information specified in para graphs (j)(2)(ii)(A) through (j)(2)(ii)(D) of this section for each sub-basin with atmospheri c tanks whose emissions were calculated using Calculation Method 3 and that did not control emissions with flares. (A) Sub-basin ID. (B) The number of atmospheric tanks in the sub-basin that did not control emissions with flares. (C) Annual CO 2 emissions, in metric tons CO 2 , from atmospheric tanks in the sub-basin that did not control emissions with flares, cal culated using Equation W-15 of this subpart. (D) Annual CH 4 emissions, in metric tons CH 4 , from atmospheric tanks in the sub-basin that vented gas directly to the atmosphere, calculated using Equation W-15 of this subpart. (iii) Report the information specified in paragr aphs (j)(2)(iii)(A) through (j)(2)(iii)(E) of this section for each sub-basin with atmospheri c tanks whose emissions were calculated using Calculation Method 3 and that controlled emissions with flares. (A) Sub-basin ID. (B) The number of atmospheric tanks in the sub-basin that controlled emissions with flares. (C) Annual CO 2 emissions, in metric tons CO 2 , from atmospheric tanks that controlled emissions with flares. (D) Annual CH 4 emissions, in metric tons CH 4 , from atmospheric tanks that controlled emissions with flares. (E) Annual N 2 O emissions, in metric tons N 2 O, from atmospheric tanks that controlled emissions with flares.Page 168 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) If any gas-liquid separator liquid dump values did not close properly during the calendar year, then you must report the information specified in paragraphs (j)(3)(i) through (j)(3)(iv) of this section. (i) The total number of gas-liquid separators whose liquid dump valves did not close properly during the calendar year. (ii) The total time the dump valves on gas-liquid separators did not close properly in the calendar year, in hours (“T n ” in Equation W-16 of this subpart). (iii) Annual CO 2 emissions, in metric tons CO 2 , that resulted from dump valves on gasliquid separators not closing properly during the calendar year, calculated using Equation W-16 of this subpart. (iv) Annual CH 4 emissions, in metric tons CH 4 , that resulted from the dump valves on gas-liquid separators not closing properly duri ng the calendar year, calculated using Equation W16 of this subpart. (k) Transmission storage tanks . You must indicate whether your facility contains any transmission storage tanks. If your facility contai ns at least one transmission storage tank, then you must report the information specified in paragraphs (k)(1) through (k)(3) of this section for each transmission storage tank vent stack. (1) For each transmission storage tank vent stack, report the information specified in (k)(1)(i) through (k)(1)(iv) of this section. (i) The unique name or ID number for the transmission storage tank vent stack. (ii) Method used to determine if dump valve leakage occurred. (iii) Indicator whether scrubber dump valve leakage occurred for the transmission storage tank vent.Page 169 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iv) Indicator if there is a flare attached to the transmission storage tank vent stack. (2) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii), and the vent st ack vented directly to the atmosphere during the calendar year, then you must report the inform ation specified in paragraphs (k)(2)(i) through (k)(2)(v) of this section for each transmission storage vent stack where scrubber dump valve leakage occurred. (i) Method used to measure the leak rate. (ii) Measured leak rate (average leak rate from a continuous flow measurement device), in standard cubic feet per hour. (iii) Duration of time that venting occurred, in hours (may use best available data if a continuous flow measurement device was used). (iv) Annual CO 2 emissions, in metric tons CO 2 , that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(k)(1) through (k)(3). (v) Annual CH 4 emissions, in metric tons CH 4 , that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(k)(1) through (k)(3). (3) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii), and the vent st ack vented to a flare during the calendar year, then you must report the information specified in paragraphs (k)(3)(i) through (k)(3)(vi) of this section. (i) Method used to measure the leak rate. (ii) Measured leakage rate (average leak rate from a continuous flow measurement device) in standard cubic feet per hour.Page 170 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iii) Duration of time that flaring occurred in hours (may use best available data if a continuous flow measurement device was used). (iv) Annual CO 2 emissions, in metric tons CO 2 , that resulted from flaring gas, calculated according to § 98.233(k)(4). (v) Annual CH 4 emissions, in metric tons CH 4 , that resulted from flaring gas, calculated according to § 98.233(k)(4). (vi) Annual N 2 O emissions, in metric tons N 2 O, that resulted from flaring gas, calculated according to § 98.233(k)(4). (l) Well testing . You must indicate whether you performed gas well or oil well testing, and if the testing of gas wells or oil wells resu lted in vented or flared emissions during the calendar year. If you performed well testing that resulted in vented or flared emissions during the calendar year, then you must report the informati on specified in paragraphs (l)(1) through (l)(4) of this section, as applicable. (1) If you used Equation W-17A to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions ar e not vented to a flare, then you must report the information specified in paragraphs (l)( 1)(i) through (l)(1)(vi) of this section. (i) Number of wells tested in the calendar year. (ii) Average number of well testing days in the calendar year. (iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil. (iv) Average flow rate for well(s) tested, in barrels of oil per day. (v) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(l). (vi) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(l).Page 171 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (2) If you used Equation W-17A to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions ar e vented to a flare, then you must report the information specified in paragraphs (l)(2)(i) through (l)(2)(vii) of this section. (i) Number of wells tested in the calendar year. (ii) Average number of well testing days in the calendar year. (iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil. (iv) Average flow rate for well(s) tested, in barrels of oil per day. (v) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(l). (vi) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(l). (vii) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98.233(l). (3) If you used Equation W-17B to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were not vented to a flare, then you must report the information specified in paragraphs (l)(3)(i) through (l)(3)(v) of this section. (i) Number of wells tested in the calendar year. (ii) Average number of well testing days in the calendar year. (iii) Average annual production rate for well(s) tested, in actual cubic feet per day. (iv) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(l). (v) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(l). (4) If you used Equation W-17B to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions we re vented to a flare, then you must report the information specified in paragraphs (l)( 4)(i) through (l)(4)(vi) of this section. (i) Number of wells tested in calendar year. (ii) Average number of well testing days in the calendar year.Page 172 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iii) Average annual production rate for well(s) tested, in actual cubic feet per day. (iv) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(l). (v) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(l). (vi) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98.233(l). (m) Associated natural gas . You must indicate whether any associated gas was vented or flared during the calendar year. If associated gas was vented or flared during the calendar year, then you must report the information specified in paragraphs (m)(1) through (m)(9) of this section for each sub-basin. (1) Sub-basin ID. (2) Indicator whether any associated gas was vented directly to the atmosphere without flaring. (3) Indicator whether any associated gas was flared. (4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil (average of the “GOR” values used in Equation W-18 of this subpart). (5) Volume of oil produced, in barrels, in the calendar year during the time periods in which associated gas was vented or flared (the sum of “V p,q ” used in Equation W-18 of this subpart). (6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year during time periods in which associated gas wa s vented or flared (the sum of “SG” values used in Equation W-18 of this subpart). (7) Total volume of emissions reported elsewhere, in standard cubic feet, during time periods in which associated gas was vented or flared and which are calculated and reported underPage 173 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. other paragraphs of this section, in standard cubic feet (the sum of “ERE p,q ” values used in Equation W-18 of this subpart). (8) If you had associated gas emissions directly to the atmosphere without flaring, then you must report the information specified in pa ragraphs (m)(8)(i) through (m)(8)(iii) of this section for each sub-basin. (i) Total number of wells for which associated gas was vented directly to the atmosphere without flaring. (ii) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(m)(3) and (m)(4). (iii) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(m)(3) and (m)(4). (9) If you had associated gas emissions that were flared, then you must report theinformation specified in paragraphs (m)(9)(i) through (m)(9)(iv) of this section for each subbasin. (i) Total number of wells for which associated gas was flared. (ii) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(m)(5). (iii) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(m)(5). (iv) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98.233(m)(5). (n) Flare stacks . You must indicate if your facility contains any flare stacks. You must report the information specified in paragraphs (n)(1) through (n)(12) of this section for each flare stack at your facility, and for each industry segment applicable to your facility.Page 174 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production industry segment, a different name or ID may be used for a single flare stack for each location where it operates at in a given calendar year. (2) Indicate whether the flare stack has a continuous flow measurement device. (3) Indicate whether the flare stack has a continuous gas composition analyzer on feed gas to the flare. (4) Volume of gas sent to the flare, in standard cubic feet (“V a ” in Equation W-19 of this subpart). (5) Fraction of the feed gas sent to an un-lit flare (“Z u ” in Equation W-19 of this subpart). (6) Flare combustion efficiency, expressed as the fraction of gas combusted by a burning flare. (7) Mole fraction of CH 4 in the feed gas to the flare (“X CH4 ” in Equation W-19 of this subpart). (8) Mole fraction of CO 2 in the feed gas to the flare (“X CO2 ” in Equation W-20 of this subpart). (9) Annual CO 2 emissions, in metric tons CO 2 (refer to Equation W-20 of this subpart). (10) Annual CH 4 emissions, in metric tons CH 4 (refer to Equation W-19 of this subpart). (11) Annual N 2 O emissions, in metric tons N 2 O (refer to Equation W-40 of this subpart). (12) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used to measure emissions from the flare, then you are not required to report N 2 O and CH 4 emissions for the flare stack. (o) Centrifugal compressors . You must indicate whether your facility has centrifugal compressors. You must report the information specified in paragraphs (o)(1) and (o)(2) of thisPage 175 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. section for all centrifugal compressors at y our facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(o)(2) or (o)(4), you must report the information specified in paragraph (o)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(o)(3) or (o)(5), you must report the information specified in para graph (o)(4) of this section. Centrifugal compressors in onshore petroleum and natural gas production are not required to report information in paragraphs (o)(1) through (o)(4) of this section and instead must report the information specified in paragraph (o)(5) of this section. (1) Compressor activity data. Report the info rmation specified in paragraphs (o)(1)(i) through (o)(1)(xvi) of this section for each compressor located at your facility. (i) Unique name or ID for the centrifugal compressor. (ii) Hours in operating-mode. (iii) Hours in not-operating-depressurized-mode. (iv) Indicate whether the compressor was measured in operating-mode. (v) Indicate whether the compressor was measured in not-operating-depressurized-mode. (vi) Indicate whether any compressor sources are part of a manifolded group of
compressor sources. (vii) Indicate whether any compressor sources are routed to a flare. (viii) Indicate whether any compressor sources have vapor recovery. (ix) Indicate whether emissions from any compressor sources are captured for fuel use or are routed to a thermal oxidizer. (x) Indicate whether the compressor has blind flanges installed.Page 176 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (xi) Indicate whether the compressor has wet or dry seals. (xii) If the compressor has wet seals, the number of wet seals. (xiii) Compressor power rating (hp). (xiv) Year compressor was installed. (xv) Compressor model name and description. (xvi) Date of last maintenance shutdo wn that compressor was depressurized. (2) Compressor source emission vent . For each compressor source at each compressor, report the information specified in paragraphs (o)(2)(i) through (o)(2)(viii) of this section. (i) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(i) of this section. (ii) Centrifugal compressor source (wet seal, isolation valve, or blowdown valve). (iii) Unique name or ID for the emission vent. If the emission vent is connected to a manifolded group of compressor sources, use the same emission vent ID for each compressor

source. (iv) Emission vent type. Indicate whether the emission vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the emission vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or
vapor recovery. (v) Indicate whether an as found leak measurement(s) as identified in § 98.233(o)(2) or (o)(4) was conducted on the emission vent. (vi) Indicate whether continuous leak measur ements as identified in § 98.233(o)(3) or (o)(5) were conducted on the emission vent.Page 177 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (vii) Report emissions as specified in paragra phs (o)(2)(vii)(A) and (o)(2)(vii)(B) of this section for the emission vent. For emission vent s associated with individual compressor sources that use an as found leak measurement(s), calculate emissions by summing all emissions from all compressor mode-source combinations for the emission vent. (A) Annual CO 2 emissions, in metric tons CO 2 . (B) Annual CH 4 emissions, in metric tons CH 4 . (viii) If the emission vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational. (3) As found leak measurement sample data. If the measurement methods specified in paragraphs § 98.233(o)(2) or (o)(4) are conducted, report the information specified in paragraph (o)(3)(i) of this section. If the measurement method specified in paragraph § 98.233(o)(2) is performed, report the information specified in paragraph (o)(3)(ii) of this section. (i) For each as found leak measurement performed on an emission vent, report the information specified in paragraphs (o)(3)(i )(A) through (o)(3)(i)(E) of this section. (A) Name or ID of emission vent. Use same em ission vent ID as in paragraph (o)(2)(iii) of this section. (B) Sample date. (C) Leak measurement method. (D) Measured flow rate, in standard cubic feet per hour. (E) For each compressor attached to the emission vent, report the mode of operation the compressor was in when the sample was taken.Page 178 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) For each compressor mode-source combination where a reporter emission factor as calculated in equation W-24 was used to calculate emissions in Equation W-23, report the information specified in paragraphs (o)(3)(ii )(A) through (o)(3)(ii)(D) of this section (A) The compressor mode-source combination. (B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF m,s in Equation W-24). (C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count m in Equation W-24). (D) Indicate whether the compressor mode-s ource combination reporter emission factor is facility-specific or corporate. (4) Continuous leak measurement data. If the measurement methods specified in paragraphs § 98.233(o)(3) or (o)(5) are conducted, report the information specified in paragraphs (o)(4)(i) and (o)(4)(ii) of this section for each continuous measurement conducted on each emission vent associated with each compresso r source or manifolded group of compressor

sources. (i) Name or ID of emission vent. Use same emi ssion vent ID as in paragraph (o)(2)(iii) of this section. (ii) Measured volume of flow during the reporting year, in million standard cubic feet. (5) Centrifugal compressors with wet seal degassing vents in onshore petroleum and natural gas production must report the informa tion specified in paragraphs (o)(5)(i) through (o)(5)(iii) of this section. (i) Number of centrifugal compressors that have wet seal oil degassing vents.Page 179 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Annual CO 2 emissions, in metric tons CO 2 , from centrifugal compressors with wet seal oil degassing vents. (iii) Annual CH 4 emissions, in metric tons CH 4 , from centrifugal compressors with wet seal oil degassing vents. (p) Reciprocating compressors . You must indicate whether your facility has reciprocating compressors. You must report the information specified in paragraphs (p)(1) and (p)(2) of this section for all reciprocating compressors at y our facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(p)(2) or (p)(4), you must report the information specified in paragraph (p)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(p)(3) or (p)(5), you must report the information specified in pa ragraph (p)(4) of this section. Reciprocating compressors in onshore petroleum and natural gas production are not required to report information in paragraphs (p)(1) through (p)(4) of this section and instead must report the information specified in paragraph (p)(5) of this section. (1) Compressor activity data. Report the info rmation specified in paragraphs (p)(1)(i) through (p)(1)(xvi) of this section for each compressor located at your facility. (i) Unique name or ID for the reciprocating compressor. (ii) Hours in operating-mode. (iii) Hours in standby-depressurized-mode. (iv) Hours in not-operating-depressurized-mode. (v) Indicate whether the compressor was measured in operating-mode. (vi) Indicate whether the compressor was measured in standby-depressurized-mode.Page 180 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.(vii) Indicate whether the compressor was measured in not-operating-depressurizedmode. (viii) Indicate whether any compressor sour ces are part of a manifolded group of
compressor sources. (ix) Indicate whether any compressor sources are routed to a flare. (x) Indicate whether any compressor sources have vapor recovery. (xi) Indicate whether emissions from any compressor sources are captured for fuel use or are routed to a thermal oxidizer. (xii) Indicate whether the compressor has blind flanges installed. (xiii) Compressor power rating (hp). (xiv) Year compressor was installed. (xv) Compressor model name and description. (xvi) Date of last maintenance shutdown for rod packing replacement. (2) Compressor source emission vent. For each compressor source at each compressor, report the information specified in paragraphs (p)(2)(i) through (p)(2)(viii) of this section. (i) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of this section. (ii) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing). (iii) Unique name or ID for the emission vent. If the emission vent is connected to a manifolded group of compressor sources, use the same emission vent ID for each compressor

source. (iv) Emission vent type. Indicate whether the emission vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the emissionPage 181 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or
vapor recovery. (v) Indicate whether an as found leak measurement(s) as identified in § 98.233(p)(2) or (p)(4) was conducted on the emission vent. (vi) Indicate whether continuous leak measur ements as identified in § 98.233(p)(3) or (p)(5) were conducted on the emission vent. (vii) Report emissions as specified in paragra phs (p)(2)(vii)(A) and (p)(2)(vii)(B) of this section for the emission vent. For emission vent s associated with individual compressor sources that use an as found leak measurement(s), calculate emissions by summing all emissions from all compressor mode-source combinations for the emission vent. (A) Annual CO 2 emissions, in metric tons CO 2 . (B) Annual CH 4 emissions, in metric tons CH 4 . (viii) If the emission vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational. (3) As found leak measurement sample data. If the measurement methods specified in paragraphs § 98.233(p)(2) or (p)(4) are conducted, report the information specified in paragraph (p)(3)(i) of this section. If the measurement method specified in paragraph § 98.233(p)(2) is performed, report the information specified in paragraph (p)(3)(ii) of this section. (i) For each as found leak measurement performed on an emission vent, report the information specified in paragraphs (p)(3)(i )(A) through (p)(3)(i)(E) of this section. (A) Name or ID of emission vent. Use same em ission vent ID as in paragraph (p)(2)(iii) of this section. (B) Sample date.Page 182 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (C) Leak measurement method. (D) Measured flow rate, in standard cubic feet per hour. (E) For each compressor attached to the emission vent, report the mode of operation the compressor was in when the sample was taken. (ii) For each compressor mode-source combination where a reporter emission factor as calculated in equation W-28 was used to calculate emissions in Equation W-27, report the information specified in paragraphs (p)(3)(ii )(A) through (p)(3)(ii)(D) of this section (A) The compressor mode-source combination. (B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF m,s in Equation W-28). (C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count m in Equation W-28). (D) Indicate whether the compressor mode-s ource combination reporter emission factor is facility-specific or corporate. (4) Continuous leak measurement data. If the measurement methods specified in paragraphs § 98.233(p)(3) or (p)(5) are conducted, report the information specified in paragraphs (p)(4)(i) and (p)(4)(ii) of this section for each continuous measurement conducted on each emission vent associated with each compresso r source or manifolded group of compressor

sources. (i) Name or ID of emission vent. Use same emi ssion vent ID as in paragraph (p)(2)(iii) of this section. (ii) Measured volume of flow during the reporting year, in million standard cubic feet.Page 183 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (5) Reciprocating compressors in onshore petroleum and natural gas production must report the information specified in paragraphs (p)(5)(i) through (p)(5)(iii) of this section. (i) Number of reciprocating compressors. (ii) Annual CO 2 emissions, in metric tons CO 2 , from reciprocating compressors. (iii) Annual CH 4 emissions, in metric tons CH 4 , from reciprocating compressors. (q) Equipment leak surveys . If your facility is subject to the requirements of § 98.233(q), then you must report the information specified in paragraphs (q)(1) and (q)(2) of this section. Natural gas distribution facilities must also report the information specified in paragraph (q)(3) of this section. (1) You must report the information specified in paragraphs (q)(1)(i) and (ii) of this section. (i) The number of complete equipment leak surveys performed during the calendar year. (ii) Natural gas distribution facilities pe rforming equipment leak surveys across a multiple year leak survey cycle must report the number of years in the leak survey cycle. (2) You must indicate whether your facility c ontains any of the comp onent types listed in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), or (i)(1), for your facility’s industry segment. For each component type that is located at your facility, you must report the information specified in paragraphs (q)(2)(i) through (q)(2)(v) of this section. If a component type is located at your facility and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (q)(2)(v) of this section but report a zero (“0”) for the information required according to paragraphs (q)(2)(iii), (q)(2)(iv), and (q)(2)(v) of this section. (i) Component type.Page 184 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Total number of the surveyed component type that were identified as leaking in the calendar year (“x p ” in Equation W-30 of this subpart for the component type). (iii) Average time the surveyed components were found leaking and operational, in hours (average of “T p,z ” from Equation W-30 of this subpart for the component type). (iv) Annual CO 2 emissions, in metric tons CO 2 , for the component type. (v) Annual CH 4 emissions, in metric tons CH 4 , for the component type. (3) Natural gas distribution facilities must repo rt the information specified in paragraphs (q)(3)(i) through (q)(3)(viii) of this section. (i) Number of above grade transmission-distribution transfer stations surveyed in the calendar year. (ii) Number of meter/regulator runs at a bove grade transmission- distribution transfer stations surveyed in the calendar year (“Count MR,y ” from Equation W-31 of this subpart, for the current calendar year). (iii) Average time that meter/regulator runs surveyed in the calendar year were operational, in hours (average of “T w,y ” from Equation W-31 of this subpart, for the current calendar year). (iv) Number of above grade transmission-distribution transfer stations surveyed in the current leak survey cycle. (v) Number of meter/regulator runs at a bove grade transmission-distribution transfer stations surveyed in current leak survey cycle (sum of “Count MR,y ” from Equation W-31 of this subpart, for all calendar years in the current leak survey cycle).Page 185 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (vi) Average time that meter/regulator runs surveyed in the current leak survey cycle were operational, in hours (average of “T w,y ” from Equation W-31 of this subpart, for all years included in the leak survey cycle). (vii) Meter/regulator run CO 2 emission factor based on all surveyed transmissiondistribution transfer stations in the current leak survey cycle, in standard cubic feet of CO 2 per meter/regulator run operating hour (“EF s,MR,i ” for CO 2 calculated using Equation W-31 of this subpart). (viii) Meter/regulator run CH 4 emission factor based on all surveyed transmissiondistribution transfer stations in the current leak survey cycle, in standard cubic feet of CH 4 per meter/regulator run operating hour (“EF s,MR,i ” for CH 4 calculated using Equation W-31 of this subpart). (r) Equipment leaks by population count . If your facility is subject to the requirements of § 98.233(r), then you must report the information specified in paragraph (r)(1) of this section. Natural gas distribution facilities must also report the information specified in paragraph (r)(2) of this section. Onshore petroleum and natural gas production facilities must also report the information specified in paragraph (r)(3) of this section. (1) You must indicate whether your facility contains any of the emission source types covered by § 98.233(r), for the ap plicable industry segment. Yo u must report the information specified in paragraphs (r)(1)(i) through (r)(1)(v) of this section separately for each emission source type that is located at your facility. Onshore petroleum and natural gas production facilities must report the information specified in paragraphs (r)(1)(i) through (r)(1)(v) of this section separately by component type, service type, and geographic location (i.e., Eastern U.S or Western U.S.).Page 186 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Emission source type. Onshore petroleum a nd natural gas production facilities must report the component type, service type and geographic location. (ii) Total number of the emission source type at the facility (“Count e ” in Equation W-32A of this subpart). (iii) Average estimated time that the emission source type was operational in the calendar year, in hours (“T e ” in Equation W-32A of this subpart). (iv) Annual CO 2 emissions, in metric tons CO 2 , for the emission source type. (v) Annual CH 4 emissions, in metric tons CH 4 , for the emission source type. (2) Natural gas distribution facilities must also report the information specified in paragraphs (q)(2)(i) through (q)(2)(viii) of this section. (i) Number of above grade transmission-distr ibution transfer stations at the facility.(ii) Number of above grade metering-regulating stations that are not transmissiondistribution transfer stations at the facility. (iii) Number of below grade transmission-distr ibution transfer stations at the facility. (iv) Number of below grade metering-regula ting stations that are not transmissiondistribution transfer stations at the facility. (v) Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations (“Count MR ” in Equation W-32B of this subpart). (vi) Average estimated time that each meter/regulator run was operational in the calendar year, in hours per meter/regulator run (“T w,avg ” in Equation W-32B of this subpart). (vii) Annual CO 2 emissions, in metric tons CO 2 , from above grade metering regulating stations that are not above grade tran smission-distribution transfer stations.Page 187 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (viii) Annual CH 4 emissions, in metric tons CH 4 , from above grade metering regulating stations that are not above grade tran smission-distribution transfer stations. (3) Onshore petroleum and natural gas production facilities must also report the information specified in paragraphs (r)( 3)(i) and (r)(3)(ii) of this section. (i) Calculation method used. (ii) Onshore petroleum and natural gas production facilities must report the information specified in paragraphs (r)(3)(ii )(A) and (r)(3)(ii)(B) of this sec tion, for each major equipment type, production type (i.e., natural gas or crude oil), and geographic location combination in Tables W-1B and W-1C of this subpart. (A) An indication of whether the facility contains the major equipment type. (B) If the facility does contain the equipment type, the count of the major equipment type. (s) Offshore petroleum and natural gas production . You must report the information specified in paragraphs (s)(1) through (s)(3) of this section for each emission source type listed in the most recent BOEMRE study. (1) Annual CO 2 emissions, in metric tons CO 2 . (2) Annual CH 4 emissions, in metric tons CH 4 . (3) Annual N 2 O emissions, in metric tons N 2 O. (t) [Reserved] (u) [Reserved] (v) [Reserved] (w) EOR injection pumps . You must indicate whether CO 2 EOR injection was used at your facility during the calendar year and if any EOR injection pump blowdowns occurredPage 188 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. during the year. If any EOR injection pump blowdowns occurred during the calendar year, then you must report the information specified in paragraphs (w)(1) through (w)(8) of this section for each EOR injection pump system. (1) Sub-basin ID. (2) EOR injection pump system identifier. (3) Pump capacity, in barrels per day. (4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“V v ” in Equation W-37 of this subpart). (5) Number of blowdowns for the EOR injection pump system in the calendar year. (6) Density of critical phase EOR inject ion gas, in kilograms per cubic foot (“R c ” in Equation W-37 of this subpart). (7) Mass fraction of CO 2 in critical phase EOR injection gas (“GHG CO2 ” in Equation W37 of this subpart). (8) Annual CO 2 emissions, in metric tons CO 2 , from EOR injection pump system blowdowns. (x) EOR hydrocarbon liquids . You must indicate whether hydrocarbon liquids were produced through EOR operations. If hydrocarbon liquids were produced through EOR operations, you must report the information specified in paragraphs (x)(1) through (x)(4) of this section for each sub-basin category with EOR operations. (1) Sub-basin ID. (2) Total volume of hydrocarbon liquids produced through EOR operations in the calendar year, in barrels (“V hl ” in Equation W-38 of this subpart).Page 189 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) Average CO 2 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel un der standard conditions (“S hl ” in Equation W-38 of this subpart). (4) Annual CO 2 emissions, in metric tons CO 2 , from CO 2 retained in hydrocarbon liquids produced through EOR operations downstream of the storage tank (“Mass CO2 ” in Equation W-38 of this subpart). (y) [Reserved] (z) Combustion equipment at onshore petroleu m and natural gas production facilities and natural gas distribution facilities . If your facility is required by § 98.232(c)(22) or (i)(7) to report emissions from combustion equipment, then you must indicate whether your facility has any combustion units subject to reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section. If your facility contains any comb ustion units subject to reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section, then you must report the information specified in paragraphs (z)(1) and (z)(2) of this section, as applicable. (1) Indicate whether the combustion units include: external fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains external fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour or internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 horsepower), then you must report the information specified in paragraphs (z)(1)(i) and (z)(1)(ii) of this section for each unit type. (i) The type of combustion unit. (ii) The total number of combustion units.Page 190 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (2) Indicate whether the combustion units include: external fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or, internal fuel combustion units of any heat capacity that are compressor-drivers. If your facility contains: ex ternal fuel combustion units with a rated heat capacity greater than 5 mmBtu/hr; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers, then you must report the information specified in paragraphs (z)(2)(i) through (z)(2)(vi) for each combustion unit type and fuel type combination. (i) The type of combustion unit. (ii) The type of fuel combusted. (iii) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, gallons, or tons. (iv) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(z)(1) and (z)(2). (v) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(z)(1) and (z)(2). (vi) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98.233(z)(1) and (z)(2). (aa) Each facility must repor t the information specified in paragraphs (aa)(1) through (aa)(9) of this section, for each applicable industry segment, by using best available data. If a quantity required to be reported is zero, you must report zero as the value.Page 191 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (1) For onshore petroleum and natural gas production, report the data specified in paragraphs (aa)(1)(i) and (aa)(1)(ii) of this section. (i) Report the information specified in paragr aphs (aa)(1)(i)(A) through (aa)(1)(i)(D) of this section for the basin as a whole. (A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not include gas injected back into reservoirs or shrinkage resulting from lease condensate production. (B) The quantity of gas produced in the calendar year for sales, in thousand standard cubic feet. (C) The quantity of crude oil ratio, and best available estimate of produced in the calendar year for sales, not including lease condensates, in barrels. (D) The quantity of lease condensate produced in the calendar year for sales, in barrels. (ii) Report the information specified in paragr aphs (aa)(1)(ii)(A) thr ough (aa)(1)(ii)(M) of this section for each unique sub-basin category. (A) State. (B) County. (C) Formation type. (D) The number of producing wells at the end of the calendar year. (E) The number of producing wells acquired during the calendar year. (F) The number of producing wells divested during the calendar year. (G) The number of wells completed during the calendar year. (H) The number of wells taken out of production during the calendar year.Page 192 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (I) Average mole fraction of CH 4 in produced gas. (J) Average mole fraction of CO 2 in produced gas. (K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic feet per barrel. (L) If an oil sub-basin, report the average API gravity of all wells. (M) If an oil sub-basin, report average low pressure separator pressure, in pounds per square inch gauge

. (2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) through (aa)(2)(iii) of this section. (i) The quantity of gas produced from the offshore platform in the calendar year for sales, in thousand standard cubic feet. (ii) The quantity of oil produced from the offshore platform in the calendar year for sales, in barrels. (iii) The quantity of condensate produced from the offshore platform in the calendar year for sales, in barrels. (3) For natural gas processing, report the quantities specified in paragraphs (aa)(3)(i) through (aa)(3)(vii) of this section. (i) The quantity of produced gas received at the gas processing plant in the calendar year, in thousand standard cubic feet. (ii) The quantity of processed (residue) gas leaving the gas processing plant in the calendar year, in thousand standard cubic feet. (iii) The quantity of NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in barrels.Page 193 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iv) The quantity of NGLs (bulk and fractionated) leaving the gas processing plant in the calendar year, in barrels. (v) Average mole fraction of CH 4 in produced gas received. (vi) Average mole fraction of CO 2 in produced gas received. (vii) Indicate whether the facility fractionates NGLs. (4) For natural gas transmission compression, report the quantity specified in paragraphs (aa)(4)(i) through (aa)(4)(v) of this section. (i) The quantity of gas transported through the compressor station in the calendar year, in thousand standard cubic feet. (ii) Number of compressors. (iii) Total compressor power rating of all compressors combined, in horsepower. (iv) Average upstream pipeline pressure, in pounds per square inch gauge. (v) Average downstream pipeline pressure, in pounds per square inch gauge. (5) For underground natural gas storage, report the quantities specified in paragraphs (aa)(5)(i) through (aa)(5)(iii) of this section. (i) The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet. (ii) The quantity of gas withdrawn from storage in the calendar year, in thousand standard cubic feet. (iii) Total storage capacity, in thousand standard cubic feet. (6) For LNG import equipment, report the quant ity of LNG imported in the calendar year, in thousand standard cubic feet.Page 194 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (7) For LNG export equipment, report the quantity of LNG exported in the calendar year, in thousand standard cubic feet. (8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (aa)(8)(iii) of this section. (i) The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet. (ii) The quantity of LNG withdrawn from storage in the calendar year , in thousand standard cubic feet. (iii) Total storage capacity, in thousand standard cubic feet. (9) For natural gas distribution, report the quantities specified in paragraphs (aa)(9)(i) through (aa)(9)(vii) of this section. (i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report. (ii) The quantity of natural gas withdrawn fr om in-system storage in the calendar year, in thousand standard cubic feet. (iii) The quantity of natural gas added to in-system storage in the calendar year, in thousand standard cubic feet. (iv) The quantity of natural gas delivered to end users, in thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for. (v) The quantity of natural gas transferred to third parties such as other LDCs or pipelines, in thousand standard cubic feet. This va lue does not include stolen gas, or gas that is otherwise unaccounted for.Page 195 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (vi) The quantity of natural gas consumed by the LDC for operational purposes, in thousand standard cubic feet. (vii) The estimated quantity of gas stolen in the calendar year, in thousand standard cubic feet. (bb) For any missing data procedures used, report the information in paragraphs (bb)(1) through (bb)(5) in this section for each individua l missing data value used in a calculation. Aggregation of missing data values within a component, well, sub-basin, or basin is not acceptable. If missing data is substituted fo r the same parameter in non-consecutive periods during the calendar year, the information in paragraphs (bb)(1) through (bb)(5) in this section should be reported for each period separately. (1) The date(s) the missing data is used. (2) The equation(s) in which the missing data is used. (3) The description of the unique or unusual circumstance that led to missing data use, including information on any equipment or components involved and any procedures that were not followed. (4) The description of the procedures used to substitute an unavailable value of a parameter. (5) The description of how the owner or operat or will avoid the use of missing data in the future, such as mitigation strategies or changes to standard operating procedures. §98.237 Records that must be retained

. Monitoring Plans, as described in §98.3(g)(5), must be completed by April 1, 2011. In addition to the information required by §98.3(g), you must retain the following records: (a) Dates on which measurements were conducted.Page 196 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (b) Results of all emissions detected and measurements. (c) Calibration reports for detection and measurement instruments used. (d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions. (e) The records required under §98.3(g)(2)(i) shall include an explanation of how company records, engineering estimation, or best available information are used to calculate each applicable parameter under this subpart. §98.238 Definitions

. Except as provided in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Acid gas means hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) contaminants that are separated from sour natural ga s by an acid gas removal unit. Acid gas removal unit (AGR) means a process unit that separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid or solid absorbents or membrane separators. Acid gas removal vent emissions mean the acid gas separated from the acid gas absorbing medium (e.g., an amine solution) and released with methane and other light hydrocarbons to the atmosphere or a flare. Associated gas venting or flaring means the venting or flaring of natural gas which 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. This does not include venting or flaring resultin g from activities that are reported elsewhere, including tank venting, well completions, and well workovers.Page 197 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Associated with a single well-pad means associated with the hydrocarbon stream as produced from one or more wells located on that single well-pad. The association ends where the stream from a single well-pad is combined with streams from one or more additional single wellpads, where the point of combination is located off that single well-pad. Onshore production storage tanks on or associated with a single we ll-pad are considered a part of the onshore production facility. Basin means geologic provinces as defined by the American Association of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991) (incorporated by refe rence, see §98.7) and the Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in Coop eration with the USGS, 1978 (incorporated by reference, see §98.7). Component means each metal to metal joint or seal of non

- welded connection separated by a compression gasket, screwed thread (with or without thread sealing compound), metal to metal compression, or fluid barrier through which natural gas or liquid can escape to the atmosphere. Compressor means any machine for raising the pressure of a natural gas or CO 2 by drawing in low pressure natural gas or CO 2 and discharging significantly higher pressure natural gas or CO 2. Compressor mode means the operational and pressurized status of a compressor. For a centrifugal compressor, “mode” refers to either operating -mode or not-operating-depressurized -Page 198 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.mode. For a reciprocating compressor, “mode” refers to either: operating -mode, standbypressurized -mode, or not-operating-depressurized -mode. Compressor source means any type of vent or valve (i.e., wet seal, blowdown valve, isolation valve, or rod packing) on a centrifugal or reciprocating compressor. Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, separated from natural gas that condenses du e to changes in the temperature, pressure, or both, and remains liquid at storage conditions. Distribution pipeline means a pipeline that is designated as such by the Pipeline and Hazardous Material Safety Administration (PHMSA) 49 CFR 192.3. Engineering estimation, for purposes of subpart W, means an estimate of emissions based on engineering principles applied to measured and/ or approximated physical parameters such as dimensions of containment, actual pressu res, actual temperatures, and compositions. Enhanced oil recovery (EOR) means the use of certain methods such as water flooding or gas injection into existing wells to increase the recovery of crude oil from a reservoir. In the context of this subpart, EOR applies to injecti on of critical phase or immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil. Equipment leak means those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally

- equivalent opening. Equipment leak detection means the process of identifying emissions from equipment, components, and other point sources. External combustion means fired combustion in which the flame and products of combustion are separated from contact with the process fluid to which the energy is delivered.Page 199 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Process fluids may be air, hot water, or hydrocarbons. External combustion equipment may include fired heaters, industrial boilers, an d commercial and domestic combustion units. Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements means the collection of all distribution pipelines and metering-regulating stations that are operated by a Local Distribution Company (LDC) within a single state that is regulated as a separate operating company by a public utility commission or that are operated as an indepe ndent municipally-owned distribution system. Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements means the collection of all distribution pipelines and metering-regulating stations that are operated by a Local Distribution Company (LDC) within a single state that is regulated as a separate operating company by a public utility commission or that are operated as an indepe ndent municipally-owned distribution system. Facility with respect to onshore petroleum and natural gas production for purposes of reporting under this subpart and for the corresponding subpart A requirements means all petroleum or natural gas equipment on a single well-pad or associated with a single well-pad and
CO 2 e OR operations that are under common ownership or common control including leased, rented, or contracted activities by an onshor e petroleum and natural gas production owner or operator and that are located in a single hydrocarbon basin as defined in §98.238. Where a person or entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility.Page 200 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Farm Taps are pressure regulation stations that deliver gas directly from transmission pipelines to generally rural cust omers. In some cases a nearby LDC may hand le the billing of the gas to the customer(s). Field means oil and gas fields identified in the United States as defined by the Energy Information Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see §98.7). Flare, for the purposes of subpart W, means a combustion device, whether at ground level or elevated, that uses an open or closed flam e to combust waste gases without energy recovery. Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole basis, that is combusted at the flare burner tip. Flare stack emissions means CO 2 and N 2 O from partial combustion of hydrocarbon gas sent to a flare plus CH 4 emissions resulting from the incomplete combustion of hydrocarbon gas in flares. Forced extraction of natural gas liquids means removal of ethane or higher carbon number hydrocarbons existing in the vapor phase in natural gas, by removing ethane or heavier hydrocarbons derived from natural gas into natural gas liquids by means of a forced extraction process. Forced extraction processes include but are not limited to refrigeration, absorption (lean oil), cryogenic expander, and combinations of these processes. Forced extraction does not include in and of itself; natural gas dehydration, or the collection or gravity separation of water or hydrocarbon liquids from natural gas at ambient temperature or heated above ambient temperatures, or the condensation of water or hydrocarbon liquids through passive reduction in pressure or temperature, or portable dewpoint suppression skids.Page 201 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Horizontal well means a well bore that has a planned deviation from primarily vertical to a primarily horizontal inclination or declination tracking in parallel with and through the target formation. Internal combustion means the combustion of a fuel that occurs with an oxidizer (usuallyair) in a combustion chamber. In an internal combustion engine the expansion of the hightemperature and -pressure gases produced by combustion applies direct force to a component of the engine, such as pistons, turbine blades, or a nozzle. This force moves the component over a distance, generating useful mechanical energy. Internal combustion equipment may include gasoline and diesel industrial engines, natural gas-fired reciprocating engines, and gas turbines. Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric pressure. LNG boil-off gas means natural gas in the gaseous phase that vents from LNG storage tanks due to ambient heat leakage through the tank insulation and heat energy dissipated in the LNG by internal pumps. Manifolded compressor source means a compressor source (as defined in this section) that is manifolded to a common vent th at routes gas from multiple compressors. Manifolded group of compressor sources means a collection of any combination of manifolded compressor sources (as defined in this section) that are manifolded to a common

vent. Meter/regulator run means a series of components used in regulating pressure or metering natural gas flow or both. At least one meter, at least on regulator, or any combination of both on a single run of piping is considered one meter/regulator run.Page 202 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Metering-regulating station means a station that meters the flowrate, regulates the pressure, or both, of natural gas in a natural gas distribution facility. This does not include customer meters, customer regulators, or farm taps. Natural gas means a naturally occurring mixture or process derivative of hydrocarbon and non-hydrocarbon gases found in geologic formations beneath the earth’s surface, of which its constituents include, but are not limited to, methane, heavier hydrocarbons and carbon dioxide. Natural gas may be field quality, pipeline quality, or process gas. Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act. Onshore petroleum and natural gas production owner or operator means the person or entity who holds the permit to operate petroleum and natural gas wells on the drilling permit or an operating permit where no drilling permit is issued, which operates an onshore petroleum and/or natural gas production facility (as described in §98.230(a)(2)). Where petroleum and natural gas wells operate without a drilling or oper ating permit, the person or entity that pays the State or Federal business income taxes is considered the owner or operator. Operating pressure means the containment pressure that characterizes the normal state of gas or liquid inside a particular pr ocess, pipeline, vessel or tank. Pressure groups as applicable to each sub-basin are defined as follows: Less than or equal to 25 psig; greater than 25 psig and less than or equal to 60 psig; greater than 60 psig and less than or equal to 110 psig; greater than 110 psig and less than or equal to 200 psig; and greater than 200 psig. The pressure in the context of pressure groups is either the well shut-in pressure;Page 203 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. well casing pressure; or you may use the casing-to-tubing pressure of one well from the same sub-basin multiplied by the tubing pressu re for each well in the sub-basin. Pump means a device used to raise pressure, drive, or increase flow of liquid streams in closed or open conduits. Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon dioxide containing light liquids from escaping the inside of a pump case to the atmosphere. Pump seal emissions means hydrocarbon gas released from the seal face between the pump internal chamber and the atmosphere. Reservoir means a porous and permeable underground natural formation containing significant quantities of hydrocarbon liquids and/or gases. Reduced emissions completion means a well completion foll owing hydraulic fracturing where gas flowback that is otherwise vented is captured, cleaned, and routed to the flow line or collection system, re-injected into the well or another well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere. Reduced emissions workover means a well workover with hydraulic fracturing (i.e., refracturing) where gas flowback that is otherwise vented is captured, cleaned, and routed to the flow line or collection system, re-injected into th e well or another well, used as an on-site fuel source, or used for other useful purpose that a pu rchased fuel or raw material would serve, with no direct release to the atmosphere. Residue Gas and Residue Gas Compression mean, respectively, production lease natural gas from which gas liquid products and, in some cases, non-hydrocarbon components have been extracted such that it meets the specifications set by a pipeline transmission company, and/or aPage 204 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. distribution company; a nd the compressors operated by the processing facility, whether inside the processing facility boundary fence or outsid e the fence-line, that deliver the residue gas from the processing facility to a transmission pipeline. Separator means a vessel in which streams of mult iple phases are gravity separated into individual streams of single phase. Sub-basin category, for onshore natural gas production, means a subdivision of a basin into the unique combination of wells with the surface coordinates within the boundaries of an individual county and subsurface completion in one or more of each of the following five formation types: Oil, high permeability gas, shale gas, coal seam, or other tight gas reservoir rock. The distinction between high permeability ga s and tight gas reservoirs shall be designated as follows: High permeability gas reservoirs with >0.1 millidarcy permeability, and tight gas reservoirs with ≤ 0.1 millidarcy permeability. Permeabil ity for a reservoir type shall be determined by engineering estimate. Wells that produce only from high permeability gas, shale gas, coal seam, or other tight gas reservoir rock are considered gas wells; gas wells producing from more than one of these formation types shall be classified into only one type based on the formation with the most contribution to productio n as determined by engineering knowledge. All wells that produce hydrocarbon liquids (with or without gas) and do not meet the definition of a gas well in this sub-basin category definition are considered to be in the oil formation. All emission sources that handle condensate from gas wells in high permeability gas, shale gas, or tight gas reservoir rock formations are considered to be in the formation that the gas well belongs to and not in the oil formation.Page 205 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Transmission-distribution (T-D) transfer station means a metering-regulating station where a local distribution company takes part or all of the natural gas from a transmission pipeline and puts it into a distribution pipeline. Transmission pipeline means a Federal Energy Regulatory Commission rate-regulated Interstate pipeline, a state rate-regulated Intrastate pipeline, or a pipeline that falls under the “Hinshaw Exemption” as referenced in section 1( c) of the Natural Gas Act, 15 U.S.C. 717-717 (w)(1994). Tubing diameter groups are defined as follows: Outer diameter less than or equal to 1 inch; outer diameter greater than 1 inch and less than 2.375 inch; and outer diameter greater than or equal to 2.375 inch. Tubing systems means piping equal to or less than one half inch diameter as per nominal pipe size. Turbine meter means a flow meter in which a ga s or liquid flow rate through the calibrated tube spins a turbine from which the spin rate is detected and calibrated to measure the fluid flow rate. Vented emissions means intentional or designed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not including st ationary combustion flue gas), including process designed flow to the atmosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas used to power equipment (such as pneumatic devices). Vertical well means a well bore that is primarily vertical but has some unintentional deviation or one or more intentional deviations to enter one or more subsurface targets that are off-set horizontally from the surface location, inter cepting the targets either vertically or at an angle.Page 206 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Well testing venting and flaring means venting and/or flaring of natural gas at the time the production rate of a well is determined for regulatory, commercial, or technical purposes. If well testing is conducted immediately after well completion or workover, then it is considered part of well completion or workover.

Table W-1A of Subpart W of Part 98—Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production Onshore petroleum and natural gas production Emission factor (scf/hour/component) Eastern U.S. Population Emission Factors—All Components, Gas Service 1 Valve 0.027 Connector 0.003 Open-ended Line 0.061 Pressure Relief Valve 0.040 Low Continuous Bleed Pneumatic Device Vents 2 1.39 High Continuous Bleed Pneumatic Device Vents 2 37.3 Intermittent Bleed Pneumatic Device Vents 2 13.5 Pneumatic Pumps 3 13.3 Population Emission Factors—All Components, Light Crude Service 4 Valve 0.05 Flange 0.003 Connector 0.007 Open-ended Line 0.05 Pump 0.01 Other 5 0.30 Population Emission Factors—All Components, Heavy Crude Service 6 Valve 0.0005 Flange 0.0009Page 207 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Onshore petroleum and natural gas production Emission factor (scf/hour/component) Connector (other) 0.0003 Open-ended Line 0.006 Other 5 0.003 Western U.S. Population Emission Factors—All Components, Gas Service 1 Valve 0.121 Connector 0.017 Open-ended Line 0.031 Pressure Relief Valve 0.193 Low Continuous Bleed Pneumatic Device Vents 2 1.39 High Continuous Bleed Pneumatic Device Vents 2 37.3 Intermittent Bleed Pneumatic Device Vents 2 13.5 Pneumatic Pumps 3 13.3 Population Emission Factors—All Components, Light Crude Service 4 Valve 0.05 Flange 0.003 Connector (other) 0.007 Open-ended Line 0.05 Pump 0.01 Other 5 0.30 Population Emission Factors—All Components, Heavy Crude Service 6 Valve 0.0005 Flange 0.0009 Connector (other) 0.0003 Open-ended Line 0.006 Other 5 0.003 1 For multi-phase flow that includes gas, use the gas service emissions factors. 2 Emission Factor is in units of “scf/hour/device.” 3 Emission Factor is in units of “scf/hour/pump.”Page 208 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 4 Hydrocarbon liquids greater than or equal to 20°API are considered “light crude.” 5 “Others” category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents. 6 Hydrocarbon liquids less than 20°API are considered “heavy crude.” Table W-1B to Subpart W of Part 98—Default Average Component Counts for Major Onshore Natural Gas Production Equipment Major equipment Valves Connectors Open-ended lines Pressure relief valves Eastern U.S. Wellheads 8 38 0.5 0 Separators 1 6 0 0 Meters/piping 12 45 0 0 Compressors 12 57 0 0 In-line heaters 14 65 2 1 Dehydrators 24 90 2 2 Western U.S. Wellheads 11 36 1 0 Separators 34 106 6 2 Meters/piping 14 51 1 1 Compressors 73 179 3 4 In-line heaters 14 65 2 1 Dehydrators 24 90 2 2

Table W-1C to Subpart W of Part 98—Default Average Component Counts For Major Crude Oil Production Equipment Major equipment Valves Flanges Connectors Open-ended lines Other components Eastern U.S. Wellhead 5 10 4 0 1 Separator 6 12 10 0 0 Heater-treater 8 12 20 0 0 Header 5 10 4 0 0Page 209 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Major equipment Valves Flanges Connectors Open-ended lines Other components Western U.S. Wellhead 5 10 4 0 1 Separator 6 12 10 0 0 Heater-treater 8 12 20 0 0 Header 5 10 4 0 0

Table W-1D of Subpart W of Part 98—Desi gnation of Eastern And Western U.S.
Eastern U.S. Western U.S. Connecticut Alabama Delaware Alaska Florida Arizona Georgia Arkansas Illinois California Indiana Colorado Kentucky Hawaii Maine Idaho Maryland Iowa Massachusetts Kansas Michigan Louisiana New Hampshire Minnesota New Jersey Mississippi New York Missouri North Carolina Montana Ohio Nebraska Pennsylvania Nevada Rhode Island New Mexico South Carolina North Dakota Tennessee OklahomaPage 210 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Eastern U.S. Western U.S. Vermont Oregon Virginia South Dakota West Virginia Texas Wisconsin Utah Washington Wyoming Table W-2 of Subpart W of Part 98—Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Processing

Onshore natural gas processing plants Emission factor (scf/hour/component) Leaker Emission Factors—Compressor Components, Gas Service Valve 1 14.84 Connector 5.59 Open-Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 Leaker Emission Factors—Non-Comp ressor Components, Gas Service Valve 1 6.42 Connector 5.71 Open-Ended Line 11.27 Pressure Relief Valve 2.01 Meter 2.93
1 Valves include control valves, block valves and regulator valves.

Table W-3 of Subpart W of Part 98—Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Tran smission Compression Onshore natural gas transmission compression Emission factor (scf/hour/component) Leaker Emission Factors—Compressor Components, Gas Service Valve 1 14.84Page 211 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Onshore natural gas transmission compression Emission factor (scf/hour/component)

Connector 5.59 Open-Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 Leaker Emission Factors—Non-Comp ressor Components, Gas Service Valve 1 6.42 Connector 5.71 Open-Ended Line 11.27 Pressure Relief Valve 2.01 Meter 2.93 Population Emission Factors—Gas Service Low Continuous Bleed Pneumatic Device Vents 2 1.37 High Continuous Bleed Pneumatic Device Vents 2 18.20 Intermittent Bleed Pneumatic Device Vents 2 2.35
1 Valves include control valves, block valves and regulator valves. 2 Emission Factor is in units of “scf/hour/device.”

Table W-4 of Subpart W of Part 98—Default Total Hydrocarbon Emission Factors for Underground Natural Gas Storage Underground natural gas storage Emis sion factor (scf/hour/component) Leaker Emission Factors—Storage Station, Gas Service Valve 1 14.84 Connector 5.59 Open-Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 Population Emission Factors—St orage Wellheads, Gas Service Connector 0.01 Valve 0.1Page 212 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Underground natural gas storage Emis sion factor (scf/hour/component) Pressure Relief Valve 0.17 Open Ended Line 0.03 Population Emission Factors—Other Components, Gas Service Low Continuous Bleed Pneumatic Device Vents 2 1.37 High Continuous Bleed Pneumatic Device Vents 2 18.20 Intermittent Bleed Pneumatic Device Vents 2 2.35
1 Valves include control valves, block valves and regulator valves. 2 Emission Factor is in units of “scf/hour/device.”

Table W-5 of Subpart W of Part 98—Default Methane Emission Factors for Liquefied Natural Gas (LNG) Storage LNG storage Emission factor (scf/hour/component) Leaker Emission Factors—LNG Storage Components, LNG Service Valve 1.19 Pump Seal 4.00 Connector 0.34 Other 1 1.77 Population Emission Factors—LNG Storage Compressor, Gas Service Vapor Recovery Compressor 2 4.17
1 “Other” equipment type should be appl ied for any equipment type other than connectors, pumps, or valves. 2 Emission Factor is in units of “scf/hour/device.”

Table W-6 of Subpart W of Part 98—Default Methane Emission Factors for LNG Import and Export Equipment LNG import and export equipment Emission factor (scf/hour/component) Leaker Emission Factors—LNG Terminals Components, LNG Service Valve 1.19 Pump Seal 4.00 Connector 0.34Page 213 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. LNG import and export equipment Emission factor (scf/hour/component) Leaker Emission Factors—LNG Terminals Components, LNG Service Other 1 1.77 Population Emission Factors—LNG Terminals Compressor, Gas Service Vapor Recovery Compressor 2 4.17
1 “Other” equipment type should be appl ied for any equipment type other than connectors, pumps, or valves. 2 Emission Factors is in units of “scf/hour/compressor.”

Table W-7 of Subpart W of Part 98—Default Methane Emission Factors for Natural Gas Distribution

Natural gas distribution Emission factor (scf/hour/ component) Leaker Emission Factors—Transmission-Distribution Transfer Station 1 Components, Gas Service Connector 1.69 Block Valve 0.557 Control Valve 9.34 Pressure Relief Valve 0.27 Orifice Meter 0.212 Regulator 0.772 Open-ended Line 26.131 Population Emission Factors—Below Grade Metering-Regulating station 1 Components, Gas Service 2 Below Grade M&R Station, Inlet Pressure > 300 psig 1.30 Below Grade M&R Station, Inlet Pressure 100 to 300 psig 0.20 Below Grade M&R Station, Inlet Pressure < 100 psig 0.10 Population Emission Factors—Distribution Mains, Gas Service 3 Unprotected Steel 12.58 Protected Steel 0.35 Plastic 1.13 Cast Iron 27.25 Population Emission Factors—Distribution Services, Gas Service 4Page 214 of 214

This document showing the proposed amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Natural gas distribution Emission factor (scf/hour/ component) Unprotected Steel 0.19 Protected Steel 0.02 Plastic 0.001 Copper 0.03
1 Excluding customer meters. 2 Emission Factor is in units of “scf/hour/station.” 3 Emission Factor is in units of “scf/hour/mile.” 4 Emission Factor is in units of “scf/hour/number of services.”