Page 1 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 chan ges to subpart W regulatory text in the proposed action: Greenhouse Gas Reporting Rule: 2015 Revisions and C onfidentiality Determinations for

Petroleum and Natural Gas Systems; Proposed Rule Signed by the EPA Administrator Gina McCarthy on No vember 13, 2014
§ 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 tempo rarily or permanently to offshore submerged lands, that houses equipment to extract hydrocarbon s from the ocean or lake floor and that processes and/or transfers such hydrocarbons to sto rage, transport vessels, or onshore. In addition, offshore production includes secondary pl atform structures connected to the platform structure via walkways, storage tanks associated wi th the platform structure and floating production and storage offloading equipment (FPSO). This source category does not include reporting of emissions from offshore drilling and e xploration that is not conducted on production platforms. (2) Onshore petroleum and natural gas production. O nshore 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, generato rs, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and processing equipment, and portable non-self-propelled equipment, which includes well drilling and complet ion equipment, workover 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). ThisPage 2 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. equipment also includes associated storage or measu rement vessels, all petroleum and natural gas production equipment located on islands, artifi cial islands, or structures connected by a causeway to land, an island, or an artificial islan d. Onshore petroleum and natural gas production also means all equipment on or associated with a si ngle enhanced oil recovery (EOR) well pad using CO 2 or natural gas injection. (3) Onshore natural gas processing. Natural gas pro cessing means the separation of natural gas liquids (NGLs) or non-methane gases fro m produced natural gas, or the separation of NGLs into one or more component mixtures. Separatio n includes one or more of the following: forced extraction of natural gas liquids, sulfur an d carbon dioxide removal, fractionation of NGLs, or the capture of CO 2 separated from natural gas streams. This segment a lso includes all residue gas compression equipment owned or operated by the natural gas processing plant. This industry segment includes processing plants that fr actionate gas liquids, and processing plants that do not fractionate gas liquids but have an ann ual average throughput of 25 MMscf per day or greater. (4) Onshore natural gas transmission compression. O nshore natural gas transmission compression means any stationary combination of com pressors that move natural gas from production fields, natural gas processing plants, o r other transmission compressors through transmission pipelines to natural gas distribution pipelines, LNG storage facilities, or into underground storage. In addition, a transmission co mpressor station includes equipment for liquids separation, and tanks for the storage of wa ter 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 fro m this segment.Page 3 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (5) Underground natural gas storage. Underground na tural gas storage means subsurface storage, including depleted gas or oil reservoirs a nd 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 n atural gas); natural gas underground storage processes and operations (including compression, de hydration and flow measurement, and excluding transmission pipelines); and all the well heads connected to the compression units located at the facility that inject and recover nat ural gas into and from the underground reservoirs. (6) Liquefied natural gas (LNG) storage. LNG storag e means onshore LNG storage vessels located above ground, equipment for liquefy ing natural gas, compressors to capture and re-liquefy boil-off-gas, re-condensers, and vaporiz ation units for re-gasification of the liquefied natural gas. (7) LNG import and export equipment. LNG import equ ipment means all onshore or offshore equipment that receives imported LNG via o cean transport, stores LNG, re-gasifies LNG, and delivers re-gasified natural gas to a natu ral 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 th e LNG via ocean transportation to any location, including locations in the United States. (8) Natural gas distribution. Natural gas distribut ion means the distribution pipelines and metering and regulating equipment at metering-regul ating stations that are operated by a Local Distribution Company (LDC) within a single state th at is regulated as a separate operating company by a public utility commission or that is o perated as an independent municipally-owned distribution system. This segment also excludes cus tomer meters and regulators, infrastructure,Page 4 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. and pipelines (both interstate and intrastate) deli vering natural gas directly to major industrial users and farm taps upstream of the local distribut ion company inlet. (9) Onshore petroleum and natural gas gathering and boosting. Onshore petroleum and natural gas gathering and boosting means gathering pipelines and other equipment used to collect petroleum and/or natural gas from onshore productio n gas or oil wells and used to compress, dehydrate, sweeten, or transport the gas to a natur al gas processing facility, a natural gas transmission pipeline or to a natural gas distribut ion pipeline. Gathering and boosting equipment includes, but is not limited to gathering pipelines , separators, compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, storag e vessels, engines, boilers, heaters, and flares. (10) Onshore natural gas transmission pipeline. Ons hore natural gas transmission pipeline means all natural gas transmission pipelines as def ined in § 98.238. (b) [Reserved] § 98.231 Reporting threshold. (a) You must report GHG emissions under this subpar t if your facility contains petroleum and natural gas systems and the facility meets the requirements of § 98.2(a)(2) , except for the industry segments in paragraphs (a)(1) through (4) of this section

. (1) Facilities must report emissions from the onshore p etroleum and natural gas production industry segment only if emission source s specified in paragraph § 98.232(c) emit 25,000 metric tons of CO 2 equivalent or more per year. (2) Facilities must report emissions from the natural gas distribution industry segment only if emission sources specified in paragraph § 9 8.232(i) emit 25,000 metric tons of CO 2 equivalent or more per year.Page 5 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) Facilities must report emissions from the onsho re petroleum and natural gas gathering and boosting industry segment only if emission sour ces specified in paragraph § 98.232(j) emit 25,000 metric tons of CO 2 equivalent or more per year. (4) Facilities must report emissions from the onsho re natural gas transmission pipeline industry segment only if emission sources specified in paragraph § 98.232(m) 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 com pression 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 s (b) through ( j ) and (m) of this section, CO 2 , CH 4 , and N 2 O emissions from each flare as specified in paragraph (b) through ( j ) 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 producti on, report CO 2 , CH 4 , and N 2 O emissions from equipment leaks, vented emission, an d flare emission source types as identified in the data collection and emissions estimation stu dy conducted by BOEMRE in compliance with 30 CFR 250.302 through 304. Offshore platforms do not need to report portable emissions. (c) For an onshore petroleum and natural gas produc tion facility, report CO 2 , CH 4 , and
N 2 O emissions from only the following source types 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. Deleted: i

Deleted: iPage 6 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (4) Well venting for liquids unloading. (5) Gas well venting during well completions withou t hydraulic fracturing. (6) W ell venting during well completions with hydraulic fracturing. (7) Gas well venting during well workovers without hydraulic fracturing. (8) W ell venting during well workovers with hydraulic fr acturing. (9) Flare stack emissions. (10) Storage tanks vented emissions from produced h ydrocarbons. (11) Reciprocating compressor venting. (12) Well testing venting and flaring. (13) Associated gas venting and flaring from produc ed 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 (s uch as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breat her caps). (22) You must use the methods in § 98.233(z) and re port under this subpart the emissions of CO 2 , CH 4 , and N 2 O from stationary or portable fuel combustion equip ment that cannot move on roadways under its own power and drive train, an d that is located at an onshore petroleum and Deleted: Gas w

Deleted: Gas wPage 7 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. natural gas production facility as defined in § 98. 238. Stationary or portable equipment are the following equipment, which are integral to the extr action, processing, or movement of oil or natural gas: well drilling and completion equipment , workover equipment, natural gas dehydrators, natural gas compressors, electrical ge nerators, steam boilers, and process heaters. (d) For onshore natural gas processing, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor 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 e nded lines, pressure relief valves, and meters. (e) For onshore natural gas transmission compressio n, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor venting. (2) Centrifugal compressor venting. (3) Transmission storage tanks. (4) Blowdown vent stacks. (5) Natural gas pneumatic device venting. (6) Flare stack emissions.Page 8 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (7) Equipment leaks from valves, connectors, open e nded 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 venting. (2) Centrifugal compressor venting. (3) Natural gas pneumatic device venting. (4) Flare stack emissions. (5) Equipment leaks from valves, connectors, open e nded 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 venting. (2) Centrifugal compressor venting. (3) Equipment leaks from valves; pump seals; connec tors; 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 venting. (2) Centrifugal compressor venting. (3) Blowdown vent stacks. (4) Equipment leaks from valves, pump seals, connec tors, vapor recovery compressors, and other equipment leak sources.Page 9 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (5) Flare stack emissions. (i) For natural gas distribution, report CO 2 , CH 4 , and N 2 O emissions from the following

sources: (1) Equipment leaks from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open-ended lines at above grade transmission-distribution transfer stations. (2) Equipment leaks at below grade transmission-dis tribution transfer stations. (3) Equipment leaks at above grade metering-regulat ing stations that are not above grade transmission-distribution transfer stations. (4) Equipment leaks at below grade metering-regulat ing stations. (5) Distribution main equipment leaks. (6) Distribution services equipment leaks. (7) Report under subpart W of this part the emissio ns of CO 2 , CH 4 , and N 2 O emissions from stationary fuel combustion sources following t he methods in § 98.233(z). (j) For an onshore petroleum and natural gas gathering and boosting facility, report CO 2 , CH 4 , and N 2 O emissions from the following source types: (1) Natural gas pneumatic device venting. (2) Natural gas driven pneumatic pump venting. (3) Acid gas removal vents. (4) Dehydrator vents. (5) Blowdown vent stacks. (6) Storage tank vented emissions. (7) Flare stack emissions. Deleted: [Reserved]Page 10 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (8) Centrifugal compressor venting. (9) Reciprocating compressor venting. (10) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other equipment leak sources (s uch as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breat her caps). (11) Gathering pipeline equipment leaks. (12) You must use the methods in § 98.233(z) and re port under this subpart the emissions of CO 2 , CH 4 , and N 2 O from stationary or portable fuel combustion equip ment that cannot move on roadways under its own power and drive train, an d that is located at an onshore petroleum and natural gas gathering and boosting facility as defi ned in § 98.238. Stationary or portable equipment includes the following equipment, which a re integral to the movement of natural gas: natural gas dehydrators, natural gas compressors, e lectrical generators, steam boilers, and process heaters. (k) Report under subpart C of this part (General St ationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary fuel combustion unit by foll owing the requirements of subpart C except for facilities und er onshore petroleum and natural gas production , onshore petroleum and natural gas gathering and b oosting, and natural gas distribution. Onshore petroleum and natural gas pro duction facilities must report stationary and portable combustion emissions as specified in parag raph (c) of this section. Natural gas distribution facilities must report stationary comb ustion emissions as specified in paragraph (i) of this section. Onshore petroleum and natural gas gathering and bo osting facilities must report stationary and portable combustion emissions as spe cified in paragraph (j) of this section.Page 11 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (l) You must report under subpart PP of this part ( Suppliers of Carbon Dioxide), CO 2 emissions captured and transferred off site by foll owing the requirements of subpart PP. (m) For onshore natural gas transmission pipeline, report CO 2 and CH 4 emissions from blowdown vent stacks. § 98.233 Calculating GHG emissions. You must calculate and report the annual GHG emissi ons as prescribed in this section. For calculations that specify measurements in actua l conditions, reporters may use a flow or volume measurement system that corrects to standard conditions and determine the flow or volume at standard conditions; otherwise, reporters must use average atmospheric conditions or typical operating conditions as applicable to the r espective 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, a nd intermittent bleed natural gas pneumatic devices using Equation W-1 of this section.



## ∑

= = 3

1 , *

* *

t t i t t i s T

GHG EF Count E (Eq. W-1)

Where:

E s,i = Annual total volumetric GHG emissions at standar d conditions in standard

cubic feet per year from natural gas pneumatic devi ce vents, of types “t” (continuous high bleed, continuous low bleed, inter mittent 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 (2) of this section. EF t = Population emission factors for natural gas pneu matic device vents (in

standard cubic feet per hour per device) of each ty pe “t” listed in Tables W1A, W-3, and W-4 of this subpart for onshore petrol eum and natural gas production, onshore natural gas transmission compre ssion, and underground natural gas storage facilities, respectively. Onshore petroleum and natural gasPage 12 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. gathering and boosting facilities must use the popu lation emission factors listed in Table W-1A. GHG i = For onshore petroleum and natural gas production facilities, onshore

petroleum and natural gas gathering and boosting fa cilities, onshore natural gas transmission compression facilities, and underg round natural gas storage facilities, concentration of GHG i , CH 4 or CO 2 , in produced natural gas or processed natural gas for each facility as specifie d in paragraphs (u)(2)(i), (iii), and (iv) of this section. T t = Average estimated number of hours in the operati ng year the devices, of each

type “t”, were operational using engineering estima tes based on best available data. Default is 8,760 hours. (1) For all industry segments, determine “Count t ” for Equation W-1 of this subpart for each type of natural gas pneumatic device (continuo us 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 repres ent the total number of devices for the reporting year. (2) For the onshore petroleum and natural gas produ ction industry segment, you have the option in the first two consecutive calendar years to determine “Count t ” for Equation W-1 of this subpart for each type of natural gas pneumatic devi ce (continuous high bleed, continuous low bleed, and intermittent bleed) using engineering es timates based on best available data. For the onshore petroleum and natural gas gathering and boo sting industry segment, you have the option in the first two consecutive calendar years to dete rmine “Count t ” for Equation W-1 of this subpart for each type of natural gas pneumatic devi ce (continuous high bleed, continuous low bleed, and intermittent bleed) using engineering es timates based on best available data. (3) For all industry segments, determine the type o f 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.Page 13 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (b) [Reserved] (c) Natural gas driven pneumatic pump venting. (1) Calculate CH 4 and CO 2 volumetric emissions from natural gas driven pneumatic pump ve nting using Equation W-2 of this section. Natural gas driven pneumatic pumps covered in parag raph (e) of this section do not have to report emissions under this paragraph (c).



### T GHG EF Count E i i s 

### *

* *

, 

### = (Eq. W-2)

Where:

E s,i = Annual total volumetric GHG emissions at standar d conditions in standard

cubic feet per year from all natural gas driven pne umatic pump venting, for GHG i . Count = Total number of natural gas driven pneumati c pumps. EF = Population emissions factors for natural gas d riven pneumatic pumps (in

standard cubic feet per hour per pump) listed in Ta ble W-1A of this subpart for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities

. 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. T = Average estimated number of hours in the operat ing year the pumps were

operational using engineering estimates based on be st available data. Default is 8,760 hours. (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 vents (in cluding processes such as amine, membrane, molecular sieve or other absorbents and a dsorbents), calculate emissions for CO 2 only (not CH 4 ) vented directly to the atmosphere or emitted thro ugh a flare, engine (e.g., permeate from a membrane or de-adsorbed gas from a pressure swing adsorber used as fuelPage 14 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. supplement), or sulfur recovery plant, using any of the calculation methods described in this paragraph (d), as applicable. (1) Calculation Method 1. If you operate and mainta in a continuous emissions monitoring system (CEMS) that has both a CO 2 concentration monitor and volumetric flow rate mon itor, you must calculate CO 2 emissions under this subpart by following the Tier 4 Calculation Method and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationar y Fuel Combustion Sources). Alternatively, you may follow the manufacturer’s instructions or indus try standard practice. If a CO 2 concentration monitor and volumetric flow rate monitor are not av ailable, you may elect to install a CO 2 concentration monitor and a volumetric flow rate mo nitor that comply with all of the requirements specified for the Tier 4 Calculation M ethod in subpart C of this part (General Stationary Fuel Combustion Sources). The calculatio n and reporting of CH 4 and N 2 O emissions is not required as part of the Tier 4 requirements for AGR units. (2) Calculation Method 2. If a CEMS is not availabl e but a vent meter is installed, use the CO 2 composition and annual volume of vent gas to calcu late emissions using Equation W-3 of this section.

2 2 CO s a,CO 

### Vol V E * = (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 t he 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 practice for cali bration of the vent meter. Vol CO2 = Annual average volumetric fraction of CO 2 content in vent gas flowing out of

the AGR unit as determined in paragraph (d)(6) of t his section.Page 15 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) Calculation Method 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 remov al unit to calculate emissions for CO 2 using Equations W-4A or W-4B of this section. If inlet ga s flow rate is known, use Equation W-4A. If outlet gas flow rate is known, use Equation W-4B.
     

− − ∗ = O O

I in a,CO Vol

Vol Vol V E 2 1 (Eq. W-4A)

     

− − ∗ = I O

I out a,CO Vol

Vol Vol V E 2 1 (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 conditions as determined using metho ds specified in paragraph (d)(5) of this section. V out = Total annual volume of natural gas flow out of t he AGR unit in cubic feet per

year at actual conditions as determined using metho ds specified in paragraph (d)(5) of this section. Vol I = 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. Vol o = Annual average volumetric fraction of CO 2 content in natural gas flowing out

of the AGR unit as determined in paragraph (d)(8) o f this section. (4) Calculation Method 4. If CEMS or a vent meter i s not installed, you may calculate emissions using any standard simulation software pa ckage, such as AspenTech HYSYS ® , or API 4679 AMINECalc, that uses the Peng-Robinson equatio n of state and speciates CO 2 emissions. A minimum of the following, determined for typical operating conditions over the calendar year by engineering estimate and process knowledge based on best available data, must be used to characterize emissions: (i) Natural gas feed temperature, pressure, and flo w rate.Page 16 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Acid gas content of feed natural gas. (iii) Acid gas content of outlet natural gas. (iv) Unit operating hours, excluding downtime for m aintenance or standby. (v) Exit temperature of natural gas. (vi) Solvent pressure, temperature, circulation rat e, and weight. (5) For Calculation Method 3, determine the gas flo w rate of the inlet when using Equation W-4A of this section or the gas flow rate of the outlet when using Equation W-4B of this section for the natural gas stream of an AGR u nit using a meter according to methods set forth in § 98.234(b). If you do not have a continuo us flow meter, either install a continuous flow meter or use an engineering calculation to determin e the flow rate. (6) For Calculation Method 2, if a continuous gas a nalyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream for each quarter that the AGR unit is operat ing to determine Vol CO2 in Equation W-3 of this section, according to the methods set forth in § 98.234(b). (7) For Calculation Method 3, if a continuous gas a nalyzer is installed on the inlet gas stream, then the continuous gas analyzer results mu st 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 for each quarter that the AGR unit is operat ing to determine Vol I in Equation W-4A or W-4B of this section, according to the methods set forth in § 98.234(b). (8) For Calculation Method 3, determine annual aver age volumetric fraction of CO 2 content in natural gas flowing out of the AGR unit using one of the methods specified in paragraphs (d)(8)(i) through (iii) of this section.Page 17 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) If a continuous gas analyzer is installed on th e 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 for each quarte r that the AGR unit is operating to determine Vol O in Equation W-4A or W-4B of this section, accordin g to the methods set forth in § 98.234(b). (iii) If a continuous gas analyzer is not available or installed, you may use the outlet pipe line quality specification for CO 2 in natural gas. (9) Calculate annual volumetric CO 2 emissions at standard conditions using calculation s in paragraph (t) of this section. (10) Calculate annual mass CO 2 emissions using calculations in paragraph (v) of t his section. (11) Determine if CO 2 emissions from the AGR unit are recovered and tran sferred outside the facility. Adjust the CO 2 emissions estimated in paragraphs (d)(1) through ( 10) of this section downward by the magnitude of CO 2 emissions recovered and transferred outside the facility. (e) Dehydrator vents. For dehydrator vents, calcula te 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 are rou ted to a vapor recovery system, you must adjust the emissions downward according to paragrap h (e)(5) of this section. If emissions from dehydrator vents are routed to a flare or regenerat or 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. Deleted: salesPage 18 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (1) Calculation Method 1. Calculate annual mass emi ssions from glycol dehydrators that have an annual average of daily natural gas through put that is greater than or equal to 0.4 million standard cubic feet per day by using a software pro gram, such as AspenTech HYSYS ® or GRIGLYCalc 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. The following parameters must be deter mined by engineering estimate based on best available data and must be used at a minimum t o 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/air pneumatic/electric). (v) Absorbent circulation rate. (vi) Absorbent type (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 composition. Determine this pa rameter using one of the methods described in paragraphs (e)(1)(xi)(A) through (D) o f this section. (A) Use the GHG mole fraction as defined in paragra ph (u)(2)(i) or (ii) of this section.Page 19 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) If the GHG mole fraction cannot be determined u sing paragraph (u)(2)(i) or (ii) of this section, select a representative analysis. (C) You may use an appropriate standard method publ ished by a consensus-based standards organization if such a method exists or y ou 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 2. Calculate annual volumetr ic emissions from glycol dehydrators that have an annual average of daily na tural 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 is 

### = (Eq. W-5)

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 dehydrato rs in thousand standard cubic

feet per dehydrator per year. Use 73.4 for CH 4 and 3.21 for CO 2 at 60 °F and 14.7 psia. Count = Total number of glycol dehydrators that hav e an annual average of daily

natural gas throughput that is less than 0.4 millio n standard cubic feet per day. 1000 = Conversion of EF i in thousand standard cubic feet to standard cubic feet. (3) Calculation Method 3. For dehydrators of any si ze that use desiccant, you must calculate emissions from the amount of gas vented f rom 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 blow down vent stacks.Page 20 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 D H E n s π = (Eq. W-6)

Where:

E s,n = Annual natural gas emissions at standard conditi ons 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).

π = pi (3.14). %G = Percent of packed vessel volume that is gas. N = Number of dehydrator openings in the calendar y ear. 100 = Conversion of %G to fraction. (4) 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, calcula te both CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions usi ng calculations in paragraphs (u) and (v) of this section. (5) Determine if the dehydrator unit has vapor reco very. Adjust the emissions estimated in paragraphs (e)(1), (2), and (3) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determin ed by engineering estimate based on best available data. (6) Calculate annual emissions from dehydrator vent s to flares or regenerator fire-box/fire tubes as follows:Page 21 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Use the dehydrator vent volume and gas composit ion as determined in paragraphs (e)(1) through (5) of this section, as applicable. (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 annual volumetric natural gas emissions from well venting for liquids unloading u sing one of the calculation methods described in paragraphs (f)(1), (2), or (3) of this section. Calculate annual CH 4 and CO 2 volumetric and mass emissions using the method desc ribed in paragraph (f)(4) of this section. (1) Calculation 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 ca tegory (see § 98.238 for the definitions of tubing diameter group, pressure group, and sub-basi n category), where gas wells are vented to the atmosphere to expel liquids accumulated in the tubing, install a recording flow meter on the vent line used to vent gas from the well (e.g., on the vent line off the wellhead separator or atmospheric storage tank) according to methods set forth in § 98.234(b). Calculate the total emissions from well venting to the atmosphere for l iquids unloading using Equation W-7A of this section. For any tubing diameter group and pre ssure group combination in a sub-basin where liquids unloading occurs both with and without plun ger lifts, Equation W-7A will be used twice, once for wells with plunger lifts and once for well s without plunger lifts. 

## ∑

= = h

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

Where:Page 22 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. E a = Annual natural gas emissions for all wells of th e same tubing diameter group

and pressure group combination in a sub-basin at ac tual conditions, a, in cubic feet. Calculate emission from wells with plun ger lifts and wells without plunger lifts separately. h = Total number of wells of the same tubing diamet er group and pressure group

combination in a sub-basin either with or without p lunger lifts. p = Wells 1 through h of the same tubing diameter g roup and pressure group

combination in a sub-basin. T p = Cumulative amount of time in hours of venting fo r each well, p, of the same

tubing diameter group and pressure group combinatio n in a sub-basin during the year. If the available venting data do not cont ain a record of the date of the venting events and data are not available to pr ovide the venting hours for the specific time period of January 1 to December 3 1, 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 a ll measured wells of the same

tubing diameter group and pressure group combinatio n in a sub-basin, 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 fo r each well, p, during the

monitoring period. MP p = Time period, in days, of the monitoring period f or each well, p. A minimum of 300 days in a calendar year are required. The ne xt period of data collection must start immediately following the end of data co llection for the previous reporting year. D p = Time period, in days during which the well, p, w as 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 in paragraphs (f)(1)(i)(A) through (C) of this section for at least one well in a unique well tubing diameter group and pressure group combi nation in each sub-basin category. Calculate emissions from wells with plunger lifts a nd wells without plunger lifts separately.Page 23 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (A) Calculate the average flow rate per hour of ven ting for each unique tubing diameter group and pressure group combination in each sub-ba sin 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) Apply the average hourly flow rate calculated u nder paragraph (f)(1)(i)(A) of this section to all wells in the same pressure group tha t have the same tubing diameter group, for the number of hours of venting these wells. (C) Calculate a new average flow rate every other c alendar year starting with the first calendar year of data collection. For a new produci ng sub-basin category, calculate an average flow rate beginning in the first year of production

. (ii) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (2) Calculation Method 2. Calculate the total emiss ions for each sub-basin from well venting to the atmosphere for liquids unloading wit hout 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 = 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 liq uids 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 monitori ng period per well, p.Page 24 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 0.37×10 −3 = {3.14 (pi)/4}/{14.7*144} (psia converted to poun ds per square feet). CD p = Casing internal diameter for each well, p, in in ches. WD p = Well depth from either the top of the well or th e 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 pr essure for wells with tubing

production, or casing pressure for each well with n o packers, in pounds per square inch absolute (psia). If casing pressure is not available for each well, you may determine the casing pressure by multiplyin g 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 kno wn. The tubing pressure must be measured during gas flow to a flow-line. Th e shut-in pressure, surface pressure, or casing pressure must be determ ined just prior to liquids unloading when the well production is impeded by li quids loading or closed to the flow-line by surface valves. SFR p = Average flow-line rate of gas for well, p, at st andard conditions in cubic feet

per hour. Use Equation W-33 of this section to calc ulate the average flowline rate at standard conditions. HR p,q = Hours that each well, p, was left open to the at mosphere during each

unloading event, q. 1.0 = Hours for average well to blowdown casing vol ume 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 3. Calculate the total emiss ions for each sub-basin from well venting to the atmosphere for liquids unloading wit h 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 = 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.Page 25 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. p = Wells 1 through W with well venting for liquids unloading for each subbasin. V p = Total number of unloading events in the monitori ng period for each well, p. 0.37×10 −3 = {3.14 (pi)/4}/{14.7*144} (psia converted to poun ds per square feet). TD p = Tubing internal diameter for each well, p, in in ches. WD p = Tubing depth to plunger bumper for each well, p, in feet. SP p = Flow-line pressure for each well, p, in pounds p er square inch absolute (psia),

using engineering estimate based on best available data. SFR p = Average flow-line rate of gas for well, p, at st andard conditions in cubic feet

per hour. Use Equation W-33 of this section to calc ulate the average flowline rate at standard conditions. HR p,q = Hours that each well, p, was left open to the at mosphere during each

unloading event, q. 0.5 = Hours for average well to blowdown tubing vol ume 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. (4) Calculate CH 4 and CO 2 volumetric and mass emissions from volumetric natu ral gas emissions using calculations in paragraphs (u) and (v) of this section. (g) W ell venting during completions and workovers with h ydraulic fracturing. Calculate annual volumetric natural gas emissions from gas we ll and oil well venting during completions and workovers involving hydraulic fracturing using Equation W-10A or Equation W-10B of this section. Equation W-10A applies to well venting whe n the gas flowback rate is measured from a specified number of example completions or workover s and Equation W-10B applies when the
gas flowback vent or flare volume is measured for each completion or workover. Completion and workover activities are separated into two peri ods, an initial period when flowback is routed 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 sufficien t to allow measurement by the devices specified Deleted: Gas wPage 26 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 mu st follow the procedures specified in paragraph (g)(1) of this section. If you elect to use Equation W-10B, you must use a recording flow meter installed on the vent line, downstream o f a separator and ahead of a flare or vent, to measure the gas flowback. Emissions must be calculated separately for complet ions and workovers, for each sub-basin, and for each well ty pe combination identified 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 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) o f 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 natural gas emissions in stand ard cubic feet from gas

venting during well completions or workovers following hydraulic fractu ring for each sub-basin and well type combination. W = Total number of wells completed or worked over using hydraulic fracturing

in a sub-basin and well type combination. T p,s = Cumulative amount of time of flowback, after suf ficient quantities of gas are present to enable separation, where gas vented or f lared for the completion or workover, in hours, for each well, p, in a sub-basi n and well type combination during the reporting year. This may inc lude non-contiguous periods of venting or flaring. T p,i = Cumulative amount of time of flowback to open tan ks/pits, from when gas is

first detected until sufficient quantities of gas a re present to enable separation, for the completion or workover, in hour s, for each well, p, in a Deleted: gas

Deleted: wellPage 27 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. sub-basin and well type combination during the repo rting year. This may include non-contiguous periods of routing to open t anks/pits. FRM s = Ratio of average gas flowback, during the period when sufficient quantit ies

of gas are present to enable separation, of well co mpletions and workovers from hydraulic fracturing to 30-day gas production rate 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. FRM i = Ratio of initial gas flowback rate during well completions and workovers

from hydraulic fracturing to 30-day gas 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 c ubic feet per hour, for the period of flow to open tanks/pits. PR s,p = Average gas production flow rate during the first 30 days of pr oduction after

completions of newly drilled wells or well workover s using hydraulic fracturing in standard cubic feet per hour of each well p, in the sub-basin and well type combination. If applicable, PR s,p may be calculated for oil wells using procedures specified in paragraph (g)(1)(vii) of this section. EnF s,p = Volume of N 2 injected gas in cubic feet at standard conditions that was

injected into the reservoir during an energized fra cture 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 conditi ons using paragraph (t) of this section. If the fracture process did not injec t gas into the reservoir or if the injected gas is CO 2 then EnF s,p is 0. FV s,p = Flow volume of vented or flared gas for each well, p, in standard cubic feet

per hour measured using a recording flow meter (digital or a nalog) on the vent line to measure gas flowback during the separation period of the completion or workover according to methods set for th in § 98.234(b). FR p,i = Flow rate vented or flared of each well, p, in s tandard cubic feet per hour

measured using a recording flow meter (digital or a nalog) on the vent line to measure the flowback, at the beginning of the perio d 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) If you elect to use Equation W-10A of this sect ion on gas wells , 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 sectio n, to determine the value of FRM s and FRM i . If you elect to use Equation W-10A of this section on oil wells, you must use Calculation Method 1 as specified in paragraph (g)(1)(i) of this section to determine the value of FRM s and FRM i . Deleted: gas Deleted: gas Deleted: that was measured

Deleted: ofPage 28 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. These values must be based on the flow rate for flo wback gases , once sufficient gas is present to enable separation. The number of measurements or ca lculations required to estimate FRM s and
FRM i must be determined individually for completions an d workovers per sub-basin and well type combination as follows: complete measurements or calculations for at least one completion or workover for less than or equal to 25 completion s or workovers for each well type combination within a sub-basin; complete measuremen ts or calculations for at least two completions or workovers for 26 to 50 completions o r workovers for each sub-basin and well type combination; complete measurements or calculat ions for at least three completions or workovers for 51 to 100 completions or workovers fo r 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 su b-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-basi n and well type combination. (i) Calculation Method 1. You must use Equation W-1 2A 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 t o determine the value of FRM i . The procedures specified in paragraphs (g)(1)(v) and (vi) of this section also apply. When making gas flowback measurements for use in Equations W-12A and W-12B o f this section, you must use a recording flow meter (digital or analog) installed on the ven t line, downstream of a separator and ahead of a flare or vent, to measure the gas flowback rates in units of standard cubic feet per hour according to methods set forth in § 98.234(b). (ii) Calculation Method 2 (for gas wells) . 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-Page 29 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 12B as specified in paragraph (g)(1)(iv) of this se ction to determine the value of FRM i . The procedures specified in paragraphs (g)(1)(v) and (v i) 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 upstre am (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 pre ssure and reservoir pressure cannot be assumed. The downstream pressure must be measured a fter the choke and atmospheric pressure cannot be assumed. Calculate flowback rate using Eq uation W-11A of this section for subsonic flow or Equation W-11B of this section for sonic fl ow. 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 equal to 2, then flow is sonic; oth erwise, flow is subsonic. Convert calculated FR a values from actual conditions upstream of the restr iction orifice to standard conditions (FR s,p and
FR i,p ) for use in Equations W-12A and W-12B of this sect ion 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 = Flowback rate in actual cubic feet per hour, und er actual subsonic flow

conditions. A = Cross sectional open area of the restriction or ifice (m 2 ). P 1 = Pressure immediately upstream of the choke (psia ). T u = Temperature immediately upstream of the choke (d egrees Kelvin). P 2 = Pressure immediately downstream of the choke (ps ia).Page 30 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 = Flowback rate in actual cubic feet per hour, und er actual sonic flow

conditions. A = Cross sectional open area of the restriction or ifice (m 2 ). T u = Temperature immediately upstream of the choke (d egrees 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:

R = Pressure ratio. P 1 = Pressure immediately upstream of the choke (psia ). P 2 = Pressure immediately downstream of the choke (ps ia). (iii) For Equation W-10A of this section, calculate FRM s using Equation W-12A of this section.



## ∑ ∑

= = = N

p p

s N

p p

s

s PR FR FRM

1 ,

1 , (Eq. W-12A)

Where:

FRM s = Ratio of average gas flowback rate, during the period of time when suffi cient

quantities of gas are present to enable separation, of well completions and workovers from hydraulic fracturing to 30-day gas production rate for each sub-basin and well type combination.Page 31 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. FR s,p = Measured average gas flowback rate from Calculation Method 1 described i n

paragraph (g)(1)(i) of this section or calculated a verage flowback rate from Calculation Method 2 described in paragraph (g)(1)( ii) of this section, during the separation period in standard cubic feet per ho ur for well(s) p for each sub-basin and well type combination. Convert measur ed and calculated FR a values from actual conditions upstream of the restr iction 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 = Average gas production flow rate during the first 30 days of pr oduction after

completions of newly drilled wells or well workover s using hydraulic fracturing, in standard cubic feet per hour for eac h well, p, that was measured in the sub-basin and well type combination. If applicable, PR s,p may be calculated for oil wells using procedures specified in paragraph (g)(1)(vii) of this section. N = Number of measured or calculated well completio ns or workovers using

hydraulic fracturing in a sub-basin and well type c ombination. (iv) For Equation W-10A of this section, calculate FRM i using Equation W-12B of this section.



# ∑ ∑

= = = N

p p

s N

p p

i
PR FR FRMi

1 ,

1 , (Eq. W-12B)

Where:

FRM i = Ratio of initial gas flowback rate during well comp letions and workovers

from hydraulic fracturing to 30-day gas production rate for the sub-basin and well type combination, for the period of flow to op en tanks/pits. FR i,p = Initial measured gas flowback rate from Calculat ion Method 1 described in

paragraph (g)(1)(i) of this section or initial calc ulated 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 ea ch sub-basin and well type combination. Measured and calculated FR i,p values must be based on flow conditions at the beginning of the separation perio d and must be expressed at standard conditions. PR s,p = Average gas production flow rate during the first 30-days of pr oduction after

completions of newly drilled wells or well workover s using hydraulic fracturing, in standard cubic feet per hour of each well, p, that was measured Deleted: gas Deleted: gas

Deleted: Ratio of flowback gas rate while flowing to open tanks/pits during well completions and workovers from hydraulic fracturing to 30-day production rate.

Deleted: gas Deleted: gasPage 32 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. in the sub-basin and well type combination. If applicable, PR s,p may be calculated for oil wells using procedures specified in paragraph (g)(1)(vii) of this section. N = Number of measured or calculated well completio ns or workovers using

hydraulic fracturing in a sub-basin and well type c ombination. (v) For Equation W-10A of this section, the ratio o f gas flowback rate during well completions and workovers from hydraulic fracturing to 30-day gas production rate are applied to all well completions and well workovers, respectively, in the sub-basin and well type combination for the total number of hours of flowba ck and for the first 30 day average gas production rate for each of these wells. (vi) For Equation W-12A and W-12B of this section, calculate new flowback rates for well completions and well workovers in each sub-bas in and well type combination once every two years starting in the first calendar year of da ta collection. (vii) For oil wells where the gas production rate i s not metered and you elect to use Equation W-10A of this section, calculate the avera ge gas production rate (PR s,p ) using Equation W-12C of this section. If GOR cannot be determined from your available data, then you must use one of the procedures specified in paragraphs (g)(1 )(vii)(A) or (g)(1)(vii)(B) of this section to determine GOR. If GOR from each well is not availab le, use the GOR from a cluster of wells in the same sub-basin category.

720 *

, p

p p s V GOR PR = (Eq. W-12C)

Where:

PR s,p = Average gas production flow rate during the firs t 30 days of production after

completions of newly drilled wells or well workover s using hydraulic fracturing in standard cubic feet per hour of well p, in the sub-basin and well type combination. Deleted: for horizontal and vertical wells

Deleted: horizontal and vertical Deleted: in the gas producing sub-basin and well type combination and to all horizontal and vertical Deleted: gas produc ing

Deleted: horizontal and vertical gas Deleted: horizontal and vertical gas Deleted: category

Field Code ChangedPage 33 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. GOR p = Average gas to oil ratio during the first 30 day s of production after

completions of newly drilled wells or workovers usi ng hydraulic fracturing in standard cubic feet of gas per barrel of oil for ea ch well p, that was measured in the sub-basin and well type combination; oil her e refers to hydrocarbon liquids produced of all API gravities. V p = Volume of oil produced during the first 30 days of production after

completions of newly drilled wells or well workover s using hydraulic fracturing in barrels of each well p, that was meas ured in the sub-basin and well type combination. 720 = Conversion from 30 days of production to hour ly production rate. (A) You may use an appropriate standard method publ ished by a consensus-based standards organization if such a method exists. (B) You may use an industry standard practice as de scribed in § 98.234(b). (2) 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 co mbination of the parameters listed in paragraphs (g)(2)(i) through (i v ) of this section. (i) Vertical or horizontal (directional drilling). (ii) With flaring or without flaring. (iii) Reduced emission completion/workover or not r educed emission completion/workover. (iv) Oil well or gas well. (3) Calculate both CH 4 and CO 2 volumetric and mass emissions from total natural g as volumetric emissions using calculations in paragrap hs (u) and (v) of this section. (4) Calculate annual emissions from well venting du ring well completions and workovers from hydraulic fracturing where all or a portion of the gas is flared as specified in paragraphs (g)(4)(i) and (ii) of this section. Deleted: ii

Deleted: gasPage 34 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Use the volumetric total natural gas emissions vented to the atmosphere during well completions and workovers as determined in paragrap h (g) of this section to calculate volumetric and mass emissions using paragraphs (u) and (v) of this section. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to adjust emissions for the portion of gas flared during well completions and workovers using hydraulic fracturing. This adjustment to emissions from compl etions 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 workove rs without hydraulic fracturing. Calculate annual volumetric natural gas emissions f rom each gas well venting during workovers without hydraulic fracturing using Equation W-13A o f this section. Calculate annual volumetric natural gas emissions from each gas well venting du ring completions without hydraulic fracturing using Equation W-13B of this section. Yo u must convert annual volumetric natural gas emissions to CH 4 and CO 2 volumetric and mass emissions as specified in para graph (h)(1) of this section. If emissions from gas well venting du ring completions and workovers without hydraulic fracturing are routed to a flare, you mus t 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-13A)

p f

p p p s T V E *

1 , 

# ∑

= = (Eq. W-13B)

Where:

E s,wo = Annual volumetric natural gas emissions in stand ard cubic feet from gas well

venting during well workovers without hydraulic fra cturing.Page 35 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. N wo = Number of workovers per sub-basin category that do not involve hydraulic

fracturing in the reporting year. EF wo = Emission factor for non-hydraulic fracture well workover venting in standard

cubic feet per workover. Use 3,114 standard cubic f eet natural gas per well workover without hydraulic fracturing. E s,p = Annual volumetric natural gas emissions in stand ard cubic feet from gas well

venting during well completions without hydraulic f racturing. p = Well completions 1 through f in a sub-basin. f = Total number of well completions without hydrau lic fracturing in a sub-basin

category. V p = Average daily gas production rate in standard cu bic feet per hour for each

well, p, undergoing completion without hydraulic fr acturing. This is the total annual gas production volume divided by total numbe r 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. T p = Time that gas is vented to either the atmosphere or a flare for each well, p,

undergoing completion without hydraulic fracturing, in hours during the year. (1) Calculate both CH 4 and CO 2 volumetric emissions from natural gas volumetric emissions using calculations in paragraph (u) of th is section. Calculate both CH 4 and CO 2 mass emissions from volumetric emissions vented to atmos phere using calculations in paragraph (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 as specified in paragraphs (h)(2)(i) and (ii) of this section. (i) Use the gas well venting volume and gas composi tion during well completions and workovers that are flared as determined using the m ethods specified in paragraphs (h) and (h)(1) of this section.Page 36 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine emissions from the flare for gas well ven ting to a flare during completions and workovers without hydraulic fracturing. (i) Blowdown vent stacks. Calculate CO 2 and CH 4 blowdown vent stack emissions from the depressurization of equipment to reduce system pressure for planned or emergency shutdowns resulting from human intervention or to t ake equipment out of service for maintenance as specified in either paragraph (i)(2) or (3) of this section. You may use the method in paragraph (i)(2) of this section for some blowdown vent stacks at your facility and the method in paragraph (i)(3) of this section for othe r blowdown vent stacks at your facility. Equipment with a unique physical volume of less tha n 50 cubic feet as determined in paragraph (i)(1) of this section are not subject to the requi rements in paragraphs (i)(2) through (4) of this section. The requirements in this paragraph (i) do not apply to blowdown vent stack emissions from depressurizing to a flare, over-pressure relie f, operating pressure control venting, blowdown of non-GHG gases, and desiccant dehydrator blowdown venting before reloading. (1) Method for calculating unique physical volumes. You must calculate each unique physical volume (including pipelines, compressor ca se or cylinders, manifolds, suction bottles, discharge bottles, and vessels) between isolation v alves, in cubic feet, by using engineering estimates based on best available data. (2) Method for determining emissions from blowdown vent stacks according to equipment or event type. If you elect to determine emissions according to each equipment or event type, using unique physical volumes as calcul ated in paragraph (i)(1) of this section, you must calculate emissions as specified in paragraph (i)(2)(i) of this section and either paragraph (i)(2)(ii) or, if applicable, paragraph (i)(2)(iii) of this section for each equipment or event type.Page 37 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Equipment or event types must be grouped into the f ollowing seven categories: facility piping (i.e., piping within the facility boundary other th an physical volumes associated with distribution pipelines), pipeline venting (i.e., physical volume s associated with distribution pipelines vented within the facility boundary), compressors, scrubbe rs/strainers, pig launchers and receivers, emergency shutdowns (this category includes emergen cy shutdown blowdown emissions regardless of equipment type), and all other equipm ent with a physical volume greater than or equal to 50 cubic feet. If a blowdown event resulte d in emissions from multiple equipment types and the emissions cannot be apportioned to the diff erent equipment types, then categorize the blowdown event as the equipment type that represent ed the largest portion of the emissions for the blowdown event. (i) Calculate the total annual natural gas emission s from each unique physical volume that is blown down using either Equation W-14A or W -14B of this section. 

## ( ) ( ) , 

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



### T P E N V V C

T P Z    

+
= −     +     (Eq. W-14A)

Where:

E s,n = Annual natural gas emissions at standard conditi ons from each unique

physical volume that is blown down, in cubic feet. N = Number of occurrences of blowdowns for each uni que physical volume in the

calendar year. V = Unique physical volume between isolation valves , in cubic feet, as calculated

in paragraph (i)(1) of this section. C = Purge factor is 1 if the unique physical volume is not purged, or 0 if the

unique physical volume is purged using non-GHG gase s. T s = Temperature at standard conditions (60 °F). T a = Temperature at actual conditions in the unique p hysical volume (°F). P s = Absolute pressure at standard conditions (14.7 p sia).Page 38 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. P a = Absolute pressure at actual conditions in the un ique physical volume (psia). Z a = Compressibility factor at actual conditions for natural gas. You may use

either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure con ditions.



## ( ) 

# ( ) ( )

, , , ,

, 1
,



### 459.67 459.67 N s a b p a e p p s n p a p s a



### T P P E V T P Z

= 

###     + −     = +     

# ∑ (Eq. W-14B)

Where:

E s,n = Annual natural gas emissions at standard conditi ons from 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 uni que physical volume in the

calendar year. V p = Unique physical volume 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 p hysical volume (°F) for each

blowdown “p”. P s = Absolute pressure at standard conditions (14.7 p sia). P a,b,p = Absolute pressure at actual conditions in the un ique physical volume (psia) at

the beginning of the blowdown “p”. P a,e,p = Absolute pressure at actual conditions in the un ique physical volume (psia) at

the end of the blowdown “p”; 0 if blowdown volume i s purged using nonGHG gases. Z a = Compressibility factor at actual conditions for natural gas. You may use

either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure con ditions. (ii) Except as allowed in paragraph (i)(2)(iii) of this section, calculate annual CH 4 and CO 2 volumetric and mass emissions from each unique phy sical volume that is blown down by using the annual natural gas emission value as calc ulated in either Equation W-14A or Equation W-14B of paragraph (i)(2)(i) of this section and th e calculation method specified in paragraphPage 39 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i)(4) of this section. Calculate the total annual CH 4 and CO 2 emissions for each equipment or event type by summing the annual CH 4 and CO 2 mass emissions for all unique physical volumes associated with the equipment or event type. (iii) For onshore natural gas transmission compress ion facilities and LNG import and export equipment, as an alternative to using the pr ocedures in paragraph (i)(2)(ii) of this section, you may elect to sum the annual natural gas emissio ns as calculated using either Equation W14A or Equation W-14B of paragraph (i)(2)(i) of thi s section for all unique physical volumes associated with the equipment type or event type. C alculate the total annual CH 4 and CO 2 volumetric and mass emissions for each equipment ty pe or event type using the sums of the total annual natural gas emissions for each equipment typ e 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 st acks as specified in paragraph (i)(2) of this section, you may use a flow meter and measure blowd own vent stack emissions for any unique physical volumes determined according to paragraph (i)(1) of this section to be greater than or equal to 50 cubic feet. If you choose to use this m ethod, you must measure the natural gas emissions from the blowdown(s) through the monitore d stack(s) using a flow meter according to methods in § 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 emission s to GHG volumetric and mass emissions. Calculate both CH 4 and CO 2 volumetric and mass emissions using the methods specified in paragraphs (u) and (v) of this section

.Page 40 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (j) Onshore production and onshore petroleum and natural gas gathering and boosting storage tanks. Calculate CH 4 , CO 2 , and N 2 O (when flared) emissions from atmospheric pressure fixed roof storage tanks receiving hydrocarbon prod uced liquids from onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering an d boosting facilities (including stationary liquid storage not owned or operated by the reporter), as specified in this paragraph (j). For gas-liquid separators wi th annual average daily throughput of oil greater than or equal to 10 barrels per day, calculate annu al CH 4 and CO 2 using Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (2) of this section. For hydrocarbon liquids flowing directly to atmospheric storage tanks without passi ng through a wellhead separator with throughput greater than or equal to 10 barrels per day, calculate annual CH 4 and CO 2 emissions using Calculation Method 2 as specified in paragrap h (j)(2) of this section. For hydrocarbon liquids flowing to gas-liquid separators or directly to at mospheric storage tanks with throughput less than 10 barrels per day, use Calculation Metho d 3 as specified in paragraph (j)(3) of this section. If you use Calculation Method 1 or Calcula tion Method 2, 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 e missions 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 e missions from atmospheric pressure fixed roof storage tanks are routed to a flare, you must calcu late CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (j)(5) of this section. (1) Calculation Method 1. Calculate annual CH 4 and CO 2 emissions from onshore production storage tanks and onshore petroleum and natural gas gathering and boosting storage tanks using operating conditions in the last wellhead gas -liquid separator before liquid transfer to Deleted: wells flowing to

Deleted: wells

Deleted: wellsPage 41 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 flashing emissions, and speciates CH 4 and CO 2 emissions that will result when the oil from the separator enters an atmospheric pressure storage ta nk. The following parameters must be determined for typical operating conditions over th e 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 pres sure. If this data is not available, determine these parameters by using one of the meth ods described in paragraphs (j)(1)(vii)(A) through (C) of this section. (A) If separator oil composition and Reid vapor pre ssure default data are provided with the software program, select the default values tha t most closely match your separator pressure first, and API gravity secondarily. (B) If separator oil composition and Reid vapor pre ssure data are available through your previous analysis, select the latest available anal ysis that is representative of produced crude oil or condensate from the sub-basin category.Page 42 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (C) Analyze a representative sample of separator oi l in each sub-basin category for oil composition and Reid vapor pressure using an approp riate standard method published by a consensus-based standards organization. (2) Calculation Method 2. Calculate annual CH 4 and CO 2 emissions using the methods in paragraph (j)(2)(i) of this section for wells flowi ng to gas-liquid 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 using the methods in paragraph (j)(2)(ii) of this section for wells with annual average daily oil production greater than or equal to 10 ba rrels per day that flow directly to atmospheric storage tanks. (i) Flow to storage tank after passing through a se parator. Assume that all of the CH 4 and CO 2 in solution at separator temperature and pressure is emitted from oil sent to storage tanks. You may use an appropriate standard method publishe d 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 com position at separator pressure and temperature. (ii) Flow to storage tank direct from wells. Calcul ate CH 4 and CO 2 emissions using either of the methods in paragraph (j)(2)(ii)(A) or (B) of this section. (A) 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 the sub-basin category and assume all of the CH 4 and CO 2 in both oil and gas are emitted from the tank. (B) 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 yourPage 43 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. well production gas/oil ratio and API gravity and a ssume all of the CH 4 and CO 2 in both oil and gas are emitted from the tank. (3) Calculation Method 3. Calculate CH 4 and CO 2 emissions using Equation W-15 of this section:



### 1000 * *

, 

### Count EF E i i s 

### = (Eq. W-15)

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 wel ls 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 an nual average daily throughput less

than 10 barrels per day. Count only separators or w ells that feed oil directly to the storage tank. 1,000 = Conversion from thousand standard cubic fee t to standard cubic feet. (4) Determine if the storage tank receiving your se parator oil has a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (j )(1) through (3) of this section downward by the magnitude of emissions recovered us ing a vapor recovery system as determined by engineering estimate based on best av ailable data. (ii) [Reserved] (5) Determine if the storage tank receiving your se parator oil is sent to flare(s). (i) Use your separator flash gas volume and gas com position as determined in this section.Page 44 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine storage tank emissions from the flare. (6) If you use Calculation Method 1 or Calculation Method 2 in paragraph (j)(1) or (2) of this section, calculate emissions from occurrences of gas-liquid separator liquid dump valves not closing during the calendar year by using Equation W-16 of this section. 

###      

= n

n n o is 

### T

E CF E *

8760 *

,, (Eq. W-16)

Where:

E s,i,o = Annual volumetric GHG emissions at standard cond itions from each storage

tank in cubic feet that resulted from the dump valv e on the gas-liquid separator not closing properly. E n = Storage tank emissions as determined in paragrap hs (j)(1), (j)(2) and, if

applicable, (j)(4) of this section in standard cubi c feet per year. T n = Total time a dump valve is not closing properly in the calendar year in hours.

Estimate T n based on maintenance, operations, or routine separator inspections that indicate the period of time when t he valve was malfunctioning in open or partially open position. CF n = Correction factor for tank emissions for time pe riod T n is 2.87 for crude oil

production. Correction factor for tank emissions fo r time period T n is 4.37 for gas condensate production. 8,760 = Conversion to hourly emissions. (7) Calculate both CH 4 and CO 2 mass emissions from natural gas volumetric emissio ns using calculations in paragraph (v) of this section

. (k) Transmission storage tanks. For vent stacks con nected to one or more transmission condensate storage tanks, either water or hydrocarb on, without vapor recovery, in onshore natural gas transmission compression, calculate CH 4 and CO 2 annual emissions from compressor scrubber dump valve leakage as specified in paragra phs (k)(1) through (4) of this section. If Deleted: well pad

Deleted: well padPage 45 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. emissions from compressor scrubber dump valve leaka ge are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (k)(5) of this section. (1) Except as specified in paragraph (k)(1)(iv) of this section, you must monitor the tank vapor vent stack annually for emissions using one o f the methods specified in paragraphs (k)(1)(i) through (iii) of this section. (i) Use an optical gas imaging instrument according to methods set forth in § 98.234(a)(1). (ii) Measure the tank vent directly using a flow me ter or high volume sampler according to methods in § 98.234(b) or (d) for a duration of 5 minutes. (iii) Measure the tank vent using a calibrated bag according to methods in § 98.234(c) for a duration of 5 minutes or until the bag is full, w hichever is shorter. (iv) You may annually monitor leakage through compr essor scrubber dump valve(s) into the tank using an acoustic leak detection device ac cording to methods set forth in § 98.234(a)(5). (2) If the tank vapors from the vent stack are cont inuous for 5 minutes, or the optical gas imaging instrument or acoustic leak detection devic e detects a leak, then you must use one of the methods in either paragraph (k)(2)(i) or (ii) of th is section. (i) Use a flow meter, such as a turbine meter, cali brated bag, or high volume sampler to estimate tank vapor volumes from the vent stack acc ording to methods set forth in § 98.234(b) through (d). If you do not have a continuous flow m easurement device, you may install a flow measuring device on the tank vapor vent stack. If t he vent is directly measured for five minutes under paragraph (k)(1)(ii) or (iii) of this section to detect continuous leakage, this serves as the

measurement.Page 46 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (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). (3) If a leaking dump valve is identified, the leak must be counted as having occurred since the beginning of the calendar year, or from t he previous test that did not detect leaking in the same calendar year. If the leaking dump valve i s 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) Use the requirements specified in paragraphs (k )(4)(i) and (ii) of this section to quantify annual emissions. (i) Use the appropriate gas composition in paragrap h (u)(2)(iii) of this section. (ii) Calculate CH 4 and CO 2 volumetric and mass emissions at standard conditio ns using calculations in paragraphs (t), (u), and (v) of thi s section, as applicable to the monitoring equipment used. (5) Calculate annual emissions from storage tanks t o flares as specified in paragraphs (k)(5)(i) and (ii) of this section. (i) Use the storage tank emissions volume and gas c omposition as determined in paragraphs (k)(1) through (4) of this section. (ii) Use the calculation method 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 annual emissions from well testing venting as specified in paragraphs (l)(1) t hrough (5) of this section. If emissions from well testing venting are routed to a flare, you mus t calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (l)(6) of this section.Page 47 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 hyd rocarbon 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 on e of the procedures specified in paragraph (l)(2)(i) or (ii) of this section to determine GOR. (i) You may use an appropriate standard method publ ished by a consensus-based standards organization if such a method exists. (ii) You may use an industry standard practice as d escribed 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 emissions from wel l(s) testing in cubic feet

under actual conditions. GOR = Gas to oil ratio in cubic feet of gas per bar rel of oil; oil here refers to hydrocarbon liquids produced of all API gravities. FR = 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 th e well(s) is tested. (4) Calculate natural gas volumetric emissions at s tandard conditions using calculations in paragraph (t) of this section.Page 48 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 natural gas volumetric emissions using calculations in paragrap hs (u) and (v) of this section. (6) Calculate emissions from well testing if emissi ons are routed to a flare as specified in paragraphs (l)(6)(i) and (ii) of this section. (i) Use the well testing emissions volume and gas c omposition as determined in paragraphs (l)(1) through (4) of this section. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine well testing emissions from the flare. (m) Associated gas venting and flaring. Calculate C H 4 and CO 2 annual emissions from associated gas venting not in conjunction with well testing (refer to paragraph (l): Well testing venting and flaring of this section) as specified i n paragraphs (m)(1) through (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 w ell is not available, use the GOR from a cluster of wells in the same sub-basin category. (2) If GOR cannot be determined from your available data, then you must use one of the procedures specified in paragraphs (m)(2)(i) or (ii ) of this section to determine GOR. (i) You may use an appropriate standard method publ ished by a consensus-based standards organization if such a method exists. (ii) You may use an industry standard practice as d escribed in § 98.234(b). (3) Estimate venting emissions using Equation W-18 of this section.Page 49 of 192

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

# ( ) 

# [ ] ∑∑

= = − = y

q x

p q p q p q p n s SG

V GOR E 1 1 , , , , * (Eq. W-18)

Where:

E s,n = Annual volumetric natural gas emissions, at the facility level, from associated

gas venting at standard conditions, in cubic feet. GOR p,q = Gas to oil ratio, for well p in sub-basin q, in standard cubic feet of gas per

barrel of oil; oil here refers to hydrocarbon liqui ds 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 wa s 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. x = Total number of wells in sub-basin that vent or flare associated gas. y = Total number of sub-basins in a basin that cont ain wells that vent or flare

associated gas. (4) Calculate both CH 4 and CO 2 volumetric and mass emissions from volumetric natu ral gas emissions using calculations in paragraphs (u) and (v) of this section. (5) Calculate emissions from associated natural gas if emissions are routed to a flare as specified in paragraphs (m)(5)(i) and (ii) of this section. (i) Use the associated natural gas volume and gas c omposition as determined in paragraph (m)(1) through (4) of this section. (ii) Use the calculation method 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 specified in paragraphs (n)(1) through (9) of this section. (1) If you have a continuous flow measurement devic e on the flare, you must use the measured flow volumes to calculate the flare gas em issions. If all of the flare gas is not measuredPage 50 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. by the existing flow measurement device, then the f low not measured can be estimated using engineering calculations based on best available da ta or company records. If you do not have a continuous flow measurement device on the flare, yo u can use engineering calculations based on process knowledge, company records, and best availa ble data. (2) If you have a continuous gas composition analyz er 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 appr opriate gas compositions for each stream of hydrocarbons going to the flare as specified in par agraphs (n)(2)(i) through (iii) of this section. (i) For onshore natural gas production and onshore petroleum and natural gas gathering and boosting , determine the GHG mole fraction using paragraph ( u)(2)(i) of this section. (ii) For onshore natural gas processing, when the s tream going to flare is natural gas, use the GHG mole fraction in feed natural gas for all s treams upstream of the de-methanizer or dew point control, and GHG mole fraction in facility sp ecific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing faciliti es. For onshore natural gas processing plants that solely fractionate a liquid stream, use the GH G mole fraction in feed natural gas liquid for all streams. (iii) For any industry segment required to report t o flare stack emissions under § 98.232, when the stream going to the flare is a hydrocarbon product stream, such as methane, ethane, propane, butane, pentane-plus and mixed light hydro carbons, then you may use a representative composition from the source for the stream determin ed by engineering calculation based on process knowledge and best available data.Page 51 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) Determine flare combustion efficiency from manu facturer. If not available, assume that flare combustion efficiency is 98 percent. (4) Convert GHG volumetric emissions to standard co nditions using calculations in paragraph (t) of this section. (5) Calculate GHG volumetric emissions from flaring at standard conditions using Equations W-19 and W-20 of this section. 

## ( ) 

## [ ] U L CH s s,CH Z Z X V E 4

4 +

− = *

1 * * η (Eq. W-19) 

# ( ) ∑

= 

### + = 5

1 

### * * * * * j L j j s CO s s,CO 

### Z R Y V X V E 2

2 

### η (Eq. W-20)

Where:

E s,CH4 = Annual CH 4 emissions from flare stack in cubic feet, at stand ard conditions. E s,CO2 = Annual CO 2 emissions from flare stack in cubic feet, at stand ard conditions. V s = Volume of gas sent to flare in standard cubic fe et, during the year as

determined in paragraph (n)(1) of this section. η = Flare combustion efficiency, expressed as fracti on of gas combusted by a

burning flare (default is 0.98). X CH4 = Mole fraction of CH 4 in the feed gas to the flare as determined in para graph

(n)(2) of this section. X CO2 = Mole fraction of CO 2 in the feed gas to the flare as determined in para graph

(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 availa ble data and operating records. Z L = Fraction of the feed gas sent to a burning flare (equal to 1- Z U ). Y j = Mole fraction of hydrocarbon constituents j (suc h as methane, ethane,

propane, butane, and pentanes-plus) in the feed gas to the flare as determined in paragraph (n)(1) of this section.Page 52 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. R j = Number of carbon atoms in the hydrocarbon consti tuent j in the feed gas to

the flare: 1 for methane, 2 for ethane, 3 for propa ne, 4 for butane, and 5 for pentanes-plus). (6) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculation in paragraph (v) of this section. (7) Calculate N 2 O emissions from flare stacks using Equation W-40 i n paragraph (z) of this section. (8) If you operate and maintain a CEMS that has bot h a CO 2 concentration monitor and volumetric flow rate monitor for the combustion gas es from the flare, you must calculate only CO 2 emissions for the flare. You must follow the Tier 4 Calculation Method and all associated calculation, quality assurance, reporting, and reco rdkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion So urces). If a CEMS is used to calculate flare stack emissions, the requirements specified in para graphs (n)(1) through (7) of this section are not required. (9) The flare emissions determined under this parag raph (n) must be corrected for flare emissions calculated and reported under other parag raphs of this section to avoid double counting of these emissions. (o) Centrifugal compressor venting. If you are requ ired 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 s pecified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2 ) through (5) of this section; perform calculations specified in paragraphs (o)(6) through (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 compressor source are routed to a flare, paragraphs (o)(1) thr ough (11) of this section do not apply andPage 53 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 (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 routed to vapor recovery, par agraphs (o)(1) through (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 facili ty as specified in § 98.232(c)(19) or an onshore petroleum and natural gas gathering and boo sting facility as specified in § 98.232(j)(8) , you must calculate volumetric emissions as specifie d in paragraph (o)(10) of this section; and calculate CH 4 and CO 2 mass emissions as specified in paragraph (o)(11) o f this section. (1) General requirements for conducting volumetric emission measurements. You must conduct volumetric emission measurements on each ce ntrifugal compressor as specified in this paragraph. Compressor sources (as defined in § 98.2 38) without manifolded vents must use a measurement method specified in paragraph (o)(1)(i) or (ii) of this section. Manifolded compressor sources (as defined in § 98.238) must us e a measurement method specified in paragraph (o)(1)(i), (ii), (iii), or (iv) of this s ection. (i) Centrifugal compressor source as found measurem ents. Measure venting from each compressor according to either paragraph (o)(1)(i)( A) or (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 specifi ed in paragraphs (o)(1)(i)(C) and (D) of this section. If additional measurements beyond the requ ired annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurementsPage 54 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. satisfying the applicable monitoring 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, yo u must measure volumetric emissions from blowdown valve leakage through the b lowdown vent as specified in either paragraph (o)(2)(i)(A) or (B) of this section and, if the compressor has wet seal oil degassing vents, measure volumetric emissions from wet seal o il degassing vents as specified in paragraph (o)(2)(ii) of this section. (B) For a compressor measured in not-operating-depr essurized-mode, you must measure volumetric emissions from isolation valve leakage a s specified in either paragraph (o)(2)(i)(A), (B), or (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 cale ndar years, provided the measurement can be taken during a scheduled shutdown. If three consecu tive 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 section at the next scheduled depressurized shutdown. The requirement specified in this paragraph does no t apply if the compressor has blind flanges in place throughout the reporting year. For purposes o f this paragraph, a scheduled shutdown means a shutdown that requires a compressor to be taken o ff-line for planned or scheduled maintenance. A scheduled shutdown does not include instances whe n a compressor is taken offline due to a decrease in demand but must remain available. (D) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for allPage 55 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. existing compressors. For only the first year of op eration of new compressors, calculate emissions according to paragraph (o)(6)(ii) of this section. (ii) Centrifugal compressor source continuous monit oring. Instead of measuring the compressor source according to paragraph (o)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric emissi ons from a compressor source as specified in paragraph (o)(3) of this section. (iii) Manifolded centrifugal compressor source as f ound measurements. For a compressor source that is part of a manifolded group of compre ssor sources (as defined in § 98.238), instead of measuring the compressor source according to par agraph (o)(1)(i), (ii), or (iv) of this section, you may elect to measure combined volumetric emissi ons from the manifolded group of compressor sources by conducting measurements at th e common vent stack as specified in paragraph (o)(4) of this section. The measurements must be conducted at the frequency specified in paragraphs (o)(1)(iii)(A) and (B) of this sectio n. (A) A minimum of one measurement must be taken for each manifolded group of compressor sources in a calendar year. (B) The measurement may be performed while the comp ressors are in any compressor mode. (iv) Manifolded centrifugal compressor source conti nuous monitoring. For a compressor source that is part of a manifolded group of compre ssor sources, instead of measuring the compressor source according to paragraph (o)(1)(i), (ii), or (iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded group of compressor sources as specified in paragraph (o)(5) of this se ction.Page 56 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (2) Methods for performing as found measurements fr om individual centrifugal compressor sources. If conducting measurements for each compressor source, you must determine the volumetric emissions from blowdown va lves and isolation valves as specified in paragraph (o)(2)(i) of this section, and the volume tric emissions 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, de termine the volumetric emissions using one of the methods specified in paragraphs (o)(2)(i)(A) through (D) of this section. (A) Determine the volumetric flow at standard condi tions 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) Determine the volumetric flow at standard condi tions from the blowdown vent using a temporary meter such as a vane anemometer accordi ng to methods set forth in § 98.234(b). (C) Use an acoustic leak detection device according to methods set forth in § 98.234(a)(5). (D) You may choose to use any of the methods set fo rth in § 98.234(a) to screen for emissions. If emissions are detected using the meth ods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (o)(2 )(i)(A) through (C) of this section. If emissions are not detected using the methods in § 9 8.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected when ever a leak is detected according to the methods.Page 57 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) For wet seal oil degassing vents in operating- mode, determine vapor volumes at standard conditions, using a temporary meter such a s a vane anemometer or permanent flow meter according to methods set forth in § 98.234(b)

. (3) Methods for continuous measurement from individ ual centrifugal compressor sources. If you elect to conduct continuous volumetric emiss ion 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 (ii) of this section. (i) Continuously measure the volumetric flow for th e individual compressor source at standard conditions using a permanent meter accordi ng to methods set forth in § 98.234(b). (ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(3)(i) of this section, the compressor 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 secti on for blowdown vent stacks. (4) Methods for performing as found measurements fr om manifolded groups of centrifugal compressor sources. If conducting measu rements for a manifolded group of compressor sources, you must measure volumetric emi ssions as specified in paragraphs (o)(4)(i) and (ii) of this section. (i) Measure at a single point in the manifold downs tream of all compressor inputs and, if practical, prior to comingling with other non-compr essor emission sources. (ii) Determine the volumetric flow at standard cond itions from the common stack using one of the methods specified in paragraphs (o)(4)(i i)(A) through (E) of this section. (A) A temporary meter such as a vane anemometer acc ording the methods set forth in § 98.234(b).Page 58 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) Calibrated bagging according to methods set for th in § 98.234(c). (C) A high volume sampler according to methods set forth § 98.234(d). (D) An acoustic leak detection device according to methods set forth in § 98.234(a)(5). (E) You may choose to use any of the methods set fo rth in § 98.234(a) to screen for emissions. If emissions are detected using the meth ods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (o)(4 )(ii)(A) through (o)(4)(ii)(D) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected when ever a leak is detected according to the method. (5) Methods for continuous measurement from manifol ded groups of centrifugal compressor sources. If you elect to conduct continu ous 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 p aragraphs (o)(5)(i) through (iii) of this section. (i) Measure at a single point in the manifold downs tream of all compressor inputs and, if practical, prior to comingling with other non-compr essor emission sources. (ii) Continuously measure the volumetric flow for t he manifolded group of compressor sources at standard conditions using a permanent me ter 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 compre ssor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to bePage 59 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (6) Method for calculating volumetric GHG emissions from as found measurements for individual centrifugal compressor sources. For comp ressor sources measured according to paragraph (o)(1)(i) of this section, you must calcu late annual GHG emissions from the compressor sources as specified in paragraphs (o)(6 )(i) through (iv) of this section. (i) Using Equation W-21 of this section, calculate the annual volumetric GHG emissions for each centrifugal compressor mode-source combina tion specified in paragraphs (o)(1)(i)(A) and (B) of this section that was measured during th e reporting year.

m i m m s m is 

### 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 c onditions, in cubic feet. MT s,m = Volumetric gas emissions for measured compressor mode-source

combination m, in standard cubic feet per hour, mea sured according to paragraph (o)(2) of this section. If multiple measu rements are performed for a given mode-source combination m, use the average of all measurements. T m = Total time the compressor is in the 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-sourc e

combination m; use the appropriate gas compositions in paragraph (u)(2) of this section. m = Compressor mode-source combination specified 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 combin ation specified in paragraph (o)(1)(i)(A) and (B) of this section that was not measured durin g the reporting year.Page 60 of 192

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

m i m m s 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 c onditions, in cubic feet. EF s,m = Reporter emission factor for compressor mode-sou rce combination m, in

standard cubic feet per hour, as calculated in para graph (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 hour s. GHG i,m = Mole fraction of GHG i in the vent gas for unmeasured compressor modesource combination m; use the appropriate gas compo sitions in paragraph (u)(2) of this section. m = Compressor mode-source combination specified 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 (B) of this section. These emission factors must be calculated annually and us ed in Equation W-23 of this section to determine volumetric emissions from a centrifugal c ompressor in the mode-source combinations that were not measured in the reporting year.

m Count

p p

m s

m s Count MT EF m 

# ∑

= = 1 ,

,

, (Eq. W-23)

Where:

EF s,m = Reporter emission factor to be used in Equation W-23 of this section for

compressor mode-source combination m, in standard c ubic feet per hour. The reporter emission factor must be based on all compr essors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years.Page 61 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. MT s,m,p = 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 (MT s,m in Equation W-21 of this section) for compressor mode-source combinatio n m for compressor p in the current reporting year and the preceding two re porting years. Count m = Total number of compressors measured in compress or mode-source

combination m in the current reporting year and the preceding two reporting years. m = Compressor mode-source combination specified 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 opera tor instead of only using measurements from a single facility. If you elect to use this op tion, the reporter emission factor must be applied to all reporting facilities for the owner or operat or. (7) Method for calculating volumetric GHG emissions from continuous monitoring of individual centrifugal compressor sources. For comp ressor 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 volumetric GHG emissions associated with the compre ssor 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.Page 62 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (8) Method for calculating volumetric GHG emissions from as found 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 th is section. If the centrifugal compressors included in the manifolded group of compressor sour ces share the manifold with reciprocating compressors, you must follow the procedures in eith er this paragraph (o)(8) or paragraph (p)(8) of this section to calculate emissions from the man ifolded group of compressor sources.

g i avg g s g g i s GHG MT T E

, , , ,, * * = (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 conditio ns, in cubic feet. T g = Total time the manifolded group of compressor so urces g had potential for

emissions in the reporting year, in hours. Include all time during which at least one compressor source in the manifolded group of compressor sources g was in a mode-source combination specified in eithe r paragraph (o)(1)(i)(A), (o)(1)(i)(B), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1) (i)(C) of this section. Default of 8760 hours may be used. MT s,g,avg = Average volumetric gas emissions of all measurem ents performed in the

reporting year according to paragraph (o)(4) of thi s section for the manifolded group of compressor sources g, in standa rd 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 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 specified in paragraph (o)(5) of this section and calculate annual volumetric GHG emissions associate d with each manifolded group ofPage 63 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. compressor sources using Equation W-24C of this sec tion. If the centrifugal compressors included in the manifolded group of compressor sour ces share the manifold with reciprocating compressors, you must follow the procedures in eith er this paragraph (o)(9) or paragraph (p)(9) of this section to calculate emissions from the man ifolded 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 conditio ns, in cubic feet. Q s,g = Volumetric gas emissions from manifolded group o f 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 compo sitions in paragraph (u)(2) of this section. (10) Method for calculating volumetric GHG emission s from wet seal oil degassing vents at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility . You must calculate emissions from centrifugal com pressor wet seal oil degassing vents at an onshore petroleu m and natural gas production facility or an onshore petroleum and natural gas gathering and boo sting facility using Equation W-25 of this section.

s i is 

### EF Count E

, , 

### * = (Eq. W-25)

Where:

E s,i = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions from centrifugal

compressor wet seals, at standard conditions, in cu bic feet. Count = Total number of centrifugal compressors tha t have wet seal oil degassing

vents.Page 64 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 from volumetric to mass emissions. You must calculate both CH 4 and CO 2 mass emissions from volumetric emissions using cal culations in paragraph (v) of this section. (12) General requirements for calculating volumetri c GHG emissions from centrifugal compressors routed to flares. You must calculate an d report emissions from all centrifugal compressor sources that are routed to a flare as sp ecified in paragraphs (o)(12)(i) through (iii) of this section. (i) Paragraphs (o)(1) through (11) of this section are not required for compressor sources that are routed to a flare. (ii) If any compressor sources are routed to a flar e, calculate the emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attri butable to compressor sources from the flare. (iii) Report all applicable activity data for compr essors with compressor sources routed to flares as specified in § 98.236(o). (p) Reciprocating compressor venting. If you are re quired to report emissions from 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 s pecified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2 ) through (5) of this section; perform calculations specified in paragraphs (p)(6) through (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) thr ough (11) of this section do not apply andPage 65 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 (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 routed to vapor recovery, par agraphs (p)(1) through (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 facili ty as specified in § 98.232(c)(11) or an onshore petroleum and natural gas gathering and boo sting facility as specified in § 98.232(j)(5) , you must calculate volumetric emissions as specifie d in paragraph (p)(10) of this section; and calculate CH 4 and CO 2 mass emissions as specified in paragraph (p)(11) o f this section. (1) General requirements for conducting volumetric emission measurements. You must conduct volumetric emission measurements on each re ciprocating compressor as specified in this paragraph. Compressor sources (as defined in § 98.2 38) without manifolded vents must use a measurement method specified in paragraph (p)(1)(i) or (ii) of this section. Manifolded compressor sources (as defined in § 98.238) must us e a measurement method specified in paragraph (p)(1)(i), (ii), (iii), or (iv) of this s ection. (i) Reciprocating compressor source as found measur ements. Measure venting from each compressor according to either paragraph (p)(1)(i)( A), (B), or (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 specifi ed in paragraphs (p)(1)(i)(D) and (E) of this section. If additional measurements beyond the requ ired annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurementsPage 66 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. satisfying the applicable monitoring 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, yo u must measure volumetric emissions from blowdown valve leakage through the b lowdown vent as specified in either paragraph (p)(2)(i)(A) or (B) of this section, and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) of this section. (B) For a compressor measured in standby-pressurize d-mode, you must measure volumetric emissions from blowdown valve leakage th rough the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (B) of this sectio n. (C) For a compressor measured in not-operating-depr essurized-mode, you must measure volumetric emissions from isolation valve leakage a s specified in either paragraph (p)(2)(i)(A), (B), or (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 cale ndar years, provided the measurement can be taken during a scheduled shutdown. If there is no s cheduled shutdown within three consecutive calendar years, you must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at the next scheduled depressurized shutdow n. For purposes of this paragraph, a scheduled shutdown means a shutdown that requires a compressor to be taken off-line for planned or scheduled maintenance. A scheduled shutd own does not include instances when a compressor is taken offline due to a decrease in de mand but must remain available. (E) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for allPage 67 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. existing compressors. For only the first year of op eration of new compressors, calculate emissions according to paragraph (p)(6)(ii) of this section. (ii) Reciprocating compressor source continuous mon itoring. 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 emissi ons from a compressor source as specified in paragraph (p)(3) of this section. (iii) Manifolded reciprocating compressor source as found measurements. For a compressor source that is part of a manifolded grou p of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (p)(1)(i), (ii), or (iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting measureme nts at the common vent stack as specified in paragraph (p)(4) of this section. The measuremen ts must be conducted at the frequency specified in paragraphs (p)(1)(iii)(A) and (B) of t his section. (A) A minimum of one measurement must be taken for each manifolded group of compressor sources in a calendar year. (B) The measurement may be performed while the comp ressors are in any compressor mode. (iv) Manifolded reciprocating compressor source con tinuous monitoring. For a compressor source that is part of a manifolded grou p of compressor sources, instead of measuring the compressor source according to paragr aph (p)(1)(i), (ii), or (iii) of this section, you may elect to continuously measure combined volu metric emissions from the manifolded group of compressors sources as specified in paragr aph (p)(5) of this section.Page 68 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (2) Methods for performing as found measurements fr om individual reciprocating compressor sources. If conducting measurements for each compressor source, you must determine the volumetric emissions from blowdown va lves and isolation valves as specified in paragraph (p)(2)(i) of this section. You must deter mine the volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section. (i) For blowdown valves on compressors in operating -mode or standby-pressurizedmode, and for isolation valves on compressors in no t-operating-depressurized-mode, determine the volumetric emissions using one of the methods s pecified in paragraphs (p)(2)(i)(A) through (D) of this section. (A) Determine the volumetric flow at standard condi tions 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) Determine the volumetric flow at standard condi tions from the blowdown vent using a temporary meter such as a vane anemometer, accord ing to methods set forth in § 98.234(b). (C) Use an acoustic leak detection device according to methods set forth in § 98.234(a)(5). (D) You may choose to use any of the methods set fo rth in § 98.234(a) to screen for emissions. If emissions are detected using the meth ods set forth in § 98.234(a), then you must use one of the methods specified in paragraphs (p)( 2)(i)(A) through (C) of this section. If emissions are not detected using the methods in § 9 8.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected when ever a leak is detected according to the method.Page 69 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) For reciprocating rod packing equipped with an open-ended vent line on compressors in operating-mode, determine the volumetric emissio ns using one of the methods specified in paragraphs (p)(2)(ii)(A) through (C) of this sectio n. (A) Determine the volumetric flow at standard condi tions from the open-ended vent line using calibrated bagging or high volume sampler acc ording to methods set forth in § 98.234(c) and § 98.234(d), respectively. (B) Determine the volumetric flow at standard condi tions from the open-ended vent line using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b). (C) You may choose to use any of the methods set fo rth in § 98.234(a) to screen for emissions. If emissions are detected using the meth ods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (p)(2 )(ii)(A) and (B) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragr aph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak i s detected according to the method. (iii) For reciprocating rod packing not equipped wi th an open-ended vent line on compressors in operating-mode, you must determine t he volumetric emissions using the method specified in paragraphs (p)(2)(iii)(A) and (B) of t his section. (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 op en distance piece, or for compressors with a closed distance piece, conduct annual detection of gas emissions from the rod packing vent, distance piece vent, compressor crank case breather cap, or other vent emitting gas from the rod packing.Page 70 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) You must measure emissions found in paragraph ( p)(2)(iii)(A) of this section using an appropriate meter, calibrated bag, or high volum e sampler according to methods set forth in § 98.234(b), (c), and (d), respectively. (3) Methods for continuous measurement from individ ual reciprocating compressor sources. If you elect to conduct continuous volumet ric 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 th e individual compressor sources at standard conditions using a permanent meter accordi ng 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 compressor 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 secti on for blowdown vent stacks. (4) Methods for performing as found measurements fr om manifolded groups of reciprocating compressor sources. If conducting mea surements for a manifolded group of compressor sources, you must measure volumetric emi ssions as specified in paragraphs (p)(4)(i) and (ii) of this section. (i) Measure at a single point in the manifold downs tream of all compressor inputs and, if practical, prior to comingling with other non-compr essor emission sources. (ii) Determine the volumetric flow at standard cond itions from the common stack using one of the methods specified in paragraph (p)(4)(ii )(A) through (E) of this section. (A) A temporary meter such as a vane anemometer acc ording the methods set forth in § 98.234(b).Page 71 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) Calibrated bagging according to methods set for th in § 98.234(c). (C) A high volume sampler according to methods set forth § 98.234(d). (D) An acoustic leak detection device according to methods set forth in § 98.234(a)(5). (E) You may choose to use any of the methods set fo rth in § 98.234(a) to screen for emissions. If emissions are detected using the meth ods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (p)(4 )(ii)(A) through (D) of this section. If emissions are not detected using the methods in § 9 8.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected when ever a leak is detected according to the method. (5) Methods for continuous measurement from manifol ded groups of reciprocating compressor sources. If you elect to conduct continu ous 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 p aragraphs (p)(5)(i) through (iii) of this section. (i) Measure at a single point in the manifold downs tream of all compressor inputs and, if practical, prior to comingling with other non-compr essor emission sources. (ii) Continuously measure the volumetric flow for t he manifolded group of compressor sources at standard conditions using a permanent me ter 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 compre ssor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to bePage 72 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (6) Method for calculating volumetric GHG emissions from as found measurements for individual reciprocating compressor sources. For co mpressor sources measured according to paragraph (p)(1)(i) of this section, you must calcu late GHG emissions from the compressor sources as specified in paragraphs (p)(6)(i) throug h (iv) of this section. (i) Using Equation W-26 of this section, calculate the annual volumetric GHG emissions for each reciprocating compressor mode-source combi nation specified in paragraphs (p)(1)(i)(A) through (C) of this section that was measured durin g the reporting year.

m i m m s m is 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 c onditions, in cubic feet. MT s,m = Volumetric gas emissions for measured compressor mode-source

combination m, in standard cubic feet per hour, mea sured according to paragraph (p)(2) of this section. If multiple measu rements are performed for a given mode-source combination m, use the average of all measurements. T m = Total time the compressor is in the mode-source combination m, for which

E s,i,m is being calculated in the reporting year, in hour s. GHG i,m = Mole fraction of GHG i in the vent gas for measured compressor mode-sourc e

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),

(B), or (C) of this section that was measured for t he reporting year. (ii) Using Equation W-27 of this section, calculate the annual volumetric GHG emissions from each reciprocating compressor mode-source comb ination specified in paragraph (p)(1)(i)(A), (B), and (C) of this section that was not measured during the reporting year.Page 73 of 192

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

m i m m s m i s GHG

T EF E

,

, ,, *

* = (Eq. W-27)

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 c onditions, in cubic feet. EF s,m = Reporter emission factor for compressor mode-sou rce combination m, in

standard cubic feet per hour, as calculated in para graph (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 hour s. GHG i,m = Mole fraction of GHG i in the vent gas for unmeasured compressor modesource combination m; use the appropriate gas compo sitions 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 tha t 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), (B), and (C) of this section. These emission factors must be calculated annually and us ed 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 reportin g year.

m Count

p p

m s

m s Count MT EF m 

# ∑

= = 1 ,

,

, (Eq. W-28)

Where:

EF s,m = Reporter emission factor to be used in Equation W-27 of this section for

compressor mode-source combination m, in standard c ubic feet per hour. The reporter emission factor must be based on all compr essors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years.Page 74 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. MT s,m,p = 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 (MT s,m in Equation W-26 of this section) for compressor mode-source combinatio n m for compressor p in the current reporting year and the preceding two re porting years. Count m = Total number of compressors measured in compress or 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),

(B), or (C) of this section. (iv) The reporter emission factor in Equation W-28 of this section may be calculated by using all measurements from a single owner or opera tor instead of only using measurements from a single facility. If you elect to use this op tion, the reporter emission factor must be applied to all reporting facilities for the owner or operat or. (7) Method for calculating volumetric GHG emissions from continuous monitoring of individual reciprocating compressor sources. For co mpressor 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 compre ssor 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 compositions in paragraph (u)(2) of this section.Page 75 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (8) Method for calculating volumetric GHG emissions from as found measurements of manifolded groups of reciprocating compressor sourc es. 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. 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 parag raph (p)(8) or paragraph (o)(8) of this section to calculate emissions from the manifolded group of compressor sources.

g i avg g s g g i s GHG MT T E

, , , ,, * * = (Eq. W-29B)

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 conditio ns, in cubic feet. T g = Total time the manifolded group of compressor so urces g had potential for

emissions in the reporting year, in hours. Include all time during which at least one compressor source in the manifolded group of compressor sources g was in a mode-source combination specified in eithe r paragraph (o)(1)(i)(A), (o)(1)(i)(B), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1) (i)(C) of this section. Default of 8760 hours may be used. MT s,g,avg = Average volumetric gas emissions of all measurem ents performed in the

reporting year according to paragraph (p)(4) of thi s section for the manifolded group of compressor sources g, in standa rd 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 source s. 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 specified in paragraph (p)(5) of this section and calculate annual volumetric GHG emissions associate d with each manifolded group ofPage 76 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. compressor sources using Equation W-29C of this sec tion. If the reciprocating compressors included in the manifolded group of compressor sour ces share the manifold with centrifugal compressors, you must follow the procedures in eith er this paragraph (p)(9) or paragraph (o)(9) of this section to calculate emissions from the man ifolded 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 conditio ns, in cubic feet. Q s,g = Volumetric gas emissions from manifolded group o f 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 compo sitions in paragraph (u)(2) of this section. (10) Method for calculating volumetric GHG emission s from reciprocating compressor venting at an onshore petroleum and natural gas pro duction facility or an onshore petroleum and natural gas gathering and boosting facility . You must calculate emissions from reciprocating compressor venting at an onshore petroleum and natu ral gas production facility or an onshore petroleum and natural gas gathering and boosting fa cility 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.Page 77 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (11) Method for converting from volumetric to mass emissions. You must calculate both CH 4 and CO 2 mass emissions from volumetric emissions using cal culations in paragraph (v) of this section. (12) General requirements for calculating volumetri c GHG emissions from reciprocating compressors routed to flares. You must calculate an d report emissions from all reciprocating compressor sources that are routed to a flare as sp ecified in paragraphs (p)(12)(i) through (iii) of this section. (i) Paragraphs (p)(1) through (11) of this section are not required for compressor sources that are routed to a flare. (ii) If any compressor sources are routed to a flar e, calculate the emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attri butable to compressor sources from the flare. (iii) Report all applicable activity data for compr essors with compressor sources routed to flares as specified in § 98.236(p). (q) Equipment leak surveys. You must use the method s described in § 98.234(a) to conduct leak detection(s) of equipment leaks from a ll component types listed in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This pa ragraph (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 C H 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 th e requirements of this paragraph (q) and do not need to be reported. For industry segments list ed in § 98.230(a)(3) through (8), if equipment leaks are detected for component types listed in th is paragraph (q), then you must calculatePage 78 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. equipment leak emissions per component type per rep orting facility using Equation W-30 of this section. For the industry segment listed in § 98.23 0(a)(8), the results from Equation W-30 are used to calculate population emission factors on a meter/regulator run basis using Equation W-31 of this section. If you chose to conduct equipment leak surveys at all above grade transmissiondistribution transfer stations over multiple years, “n,” according to paragraph (q)(8)(i) of this section, then you must calculate the emissions from all above grade transmission-distribution transfer stations as specified in paragraph (q)(9) of this section. 

# ∑

= 

### = p x

z z p p s i i p s 

### T

EF GHG E 1 , , , , 

### *

* (Eq. W-30)

Where:

E s,p,i = Annual total volumetric emissions of GHG i from 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 paragrap hs (q)(1) through (8) of this section.

x p = Total number of specific component type “p” dete cted as leaking during

annual leak surveys. EF s,p = Leaker emission factor for specific component ty pes listed in Table W-2

through Table W-7 of this subpart. GHG i = For onshore natural gas processing facilities, c oncentration 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 ga s 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”, compo nent type “p”, was

assumed to be leaking and operational, in hours. If one leak detection survey is conducted in the calendar year, assume the compo nent was leaking for the entire calendar year, accounting for time the compo nent was not operational (i.e., not operating under pressure) using engineer ing estimate based on best available data. If multiple leak detection surveys are conducted in the calendar year, assume that the component found to b e leaking has been leaking since the previous survey (if not found lea king in the previous survey) or the beginning of the calendar year (if i t was found leaking in thePage 79 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 est imate based on best available data. (1) You must conduct either one leak detection surv ey in a calendar year or multiple complete leak detection surveys in a calendar year. The leak detection surveys selected must be conducted during the calendar year. (2) Calculate both CO 2 and CH 4 mass emissions using calculations in paragraph (v) of this section. (3) Onshore natural gas processing facilities must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and noncompressor components in gas service listed in Tabl e W-2 of this subpart. (4) Onshore natural gas transmission compression fa cilities must use the appropriate default total hydrocarbon leaker emission factors f or compressor components in gas service and non-compressor components in gas service listed in Table W-3 of this subpart. (5) Underground natural gas storage facilities must use the appropriate default total hydrocarbon leaker emission factors for storage sta tions in gas service listed in Table W-4 of this subpart. (6) LNG storage facilities must use the appropriate default methane leaker emission factors for LNG storage components in gas service l isted in Table W-5 of this subpart. (7) LNG import and export facilities must use the a ppropriate default methane leaker emission factors for LNG terminals components in LN G service listed in Table W-6 of this subpart.Page 80 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (8) Natural gas distribution facilities must use Eq uation W-30 of this section and the default methane leaker emission factors for transmi ssion-distribution transfer station components in gas service listed in Table W-7 of this subpart to calculate component emissions from annual equipment leak surveys conducted at above grade tra nsmission-distribution transfer stations. Natural gas distribution facilities are required to perform equipment leak surveys only at above grade stations that qualify as transmission-distrib ution transfer stations. Below grade transmission-distribution transfer stations and all metering-regulating stations that do not meet the definition of transmission-distribution transfe r stations are not required to perform equipment leak surveys under this section. (i) Natural gas distribution facilities may choose to conduct equipment leak surveys at all above grade transmission-distribution transfer stat ions over multiple years “n”, not exceeding a five year period to cover all above grade transmiss ion-distribution transfer stations. If the facility chooses to use the multiple year option, then the n umber of transmission-distribution transfer stations that are monitored in each year should be approximately equal across all years in the cycle. (ii) Use Equation W-31 of this section to determine the meter/regulator run population emission factors for each GHG i . As additional survey data become available, you m ust recalculate the meter/regulator run population emis sion 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:Page 81 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. EF s,MR,i = Meter/regulator run population emission factor f or GHG i based on all surveyed above grade transmission-distribution tran sfer 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 co nditions 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 th is subpart for transmissiondistribution transfer stations. T w,y = The total time the surveyed meter/regulator run “w” was operational, in hours

during survey year “y” using engineering estimate b ased 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, according to paragraph (q)(8)(i) of this section,

whose results are used to calculate emission factor “EF s,MR,i ” according to paragraph (q)(8)(iii) of this section. (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 you chose to conduct equipment leak surveys at all above grade t ransmission-distribution transfer stations over multiple years, “n,” according to paragraph (q )(8)(i) of this section and you have submitted a smaller number of annual reports than the duratio n of the selected cycle period of 5 years or less, then all available data from the current year and previous years must be used in the calculation of the emission factor “EF s,MR,i ” from Equation W-31 of this section. After the fir st survey cycle of “n” years is completed and beginnin g in calendar year (n+1), the survey will continue on a rolling basis by including the survey results from the current calendar year “y” and survey results from all previous (n-1) calendar yea rs, such that each annual calculation of the emission factor “EF s,MR,i ” from Equation W-31 of this section is based on su rvey results from “n” years. Upon completion of a cycle, you may elec t to change the number of years in the nextPage 82 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. cycle period (to be 5 years or less). If the number of years in the new cycle is greater than the number of years in the previous cycle, calculate “E F s,MR,i ” from Equation W-31 of this section in each year of the new cycle using the survey results from the current calendar year and the survey results from the preceding number years that is equ al to the number of years in the previous cycle period. If the number of years, “n new ”, in the new cycle is smaller than the number of y ears in the previous cycle, “n”, calculate “EF s,MR,i ” from Equation W-31 of this section in each year o f the new cycle using the survey results from the cur rent calendar year and survey results from all previous (n new -1) calendar years. (9) If you chose to conduct equipment leak surveys at all above grade transmissiondistribution transfer stations over multiple years, “n,” according to paragraph (q)(8)(i) of this section, you must use the meter/regulator run popul ation emission factors calculated using Equation W-31 of this section and the total count o f all meter/regulator runs at above grade transmission-distribution transfer stations to calc ulate emissions from all above grade transmission-distribution transfer stations using E quation W-32B in paragraph (r) of this section. (r) Equipment leaks by population count. This parag raph applies to emissions sources listed in § 98.232(c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4), (i)(5), (i)(6) , (j)(9), and (j)(10) on streams with gas content greater than 10 percent CH 4 plus CO 2 by weight. Emissions sources in streams with gas content less than or equal to 1 0 percent CH 4 plus CO 2 by weight are exempt from the requirements of this paragraph (r) and do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt f rom the requirements of this paragraph (r) and do not need to be reported. You must calculate emis sions from all emission sources listed in this paragraph using Equation W-32A of this section, exc ept for natural gas distribution facility emission sources listed in § 98.232(i)(3). Natural gas distribution facility emission sources listed Deleted: andPage 83 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. in § 98.232(i)(3) must calculate emissions using Eq uation W-32B and according to paragraph (r)(6)(ii) 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

, , , , , *

* = (Eq. W-32B)

Where:

E s,e,i = Annual volumetric emissions of GHG i from the emission source type in

standard cubic feet. The emission source type may b e a component (e.g., connector, open-ended line, etc.), below grade mete ring-regulating station, below grade transmission-distribution transfer stat ion, distribution main, distribution service , or gathering pipeline

. E s,MR,i = Annual volumetric emissions of GHG i from all meter/regulator runs at above

grade metering regulating stations that are not abo ve grade transmissiondistribution transfer stations or, when used to cal culate emissions according to paragraph (q)(9) of this section, the annual vol umetric emissions of GHG i from all meter/regulator runs at above grade transm ission-distribution transfer stations, in standard cubic feet. Count e = Total number of the emission source type at the facility. For onshore

petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities , average component counts are provided by major equipment piece in Tables W-1B an d Table W-1C of this subpart. Use average component counts as appropriat e for operations in Eastern and Western U.S., according to Table W-1D o f this subpart. Onshore petroleum and natural gas gathering and boosting fa cilities must also count the miles of gathering pipelines. Underground natural gas storage facilities must count each component listed in Table W-4 of th is subpart. LNG storage facilities must count the number of vapor recovery compressors. LNG import and export facilities must count the number of vapo r recovery compressors. Natural gas distribution facilities must count: (1) the number of distribution services by material type; (2) miles of distributio n mains by material type; and (3) number of below grade metering-regulating s tations, by pressure type; as listed in Table W-7 of this subpart. Count MR = Total number of meter/regulator runs at above gr ade metering-regulating

stations that are not above grade transmission-dist ribution transfer stations or, when used to calculate emissions according to parag raph (q)(9) of this section, the total number of meter/regulator runs a t above grade transmissiondistribution transfer stations. Deleted: orPage 84 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. EF s,e = Population emission factor for the specific emis sion source type, as listed in

Tables W-1A and W-4 through W-7 of this subpart. Us e appropriate population emission factor for operations in Easter n and Western U.S., according to Table W-1D of this subpart. EF s,MR,i = Meter/regulator run population emission factor f or GHG i based on all surveyed above grade transmission-distribution tran sfer stations over “n” years, in standard cubic feet of GHG i per operational hour of all meter/regulator runs, as determined in Equation W-3 1. GHG i = For onshore petroleum and natural gas production facilities and onshore

petroleum and natural gas gathering and boosting fa cilities , 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 equipme nt, 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 e = Average estimated time that each emission source type associated with the

equipment leak emission was operational in the cale ndar 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, us ing 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 fa cilities and onshore petroleum and natural gas gathering and boosting facilities must use the appropriate default whole gas population emission factors listed in Table W-1A of this subpart. Major equipment and components associated with gas wells and onshore petroleum and natural gas gathering and boosting systems are considered gas service components in reference to Table W-1A of this subpart and major natural gas equipment in referenc e 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 subpa rt and major crude oil equipment in reference to Table W-1C of this subpart. Where faci lities conduct EOR operations the emissionsPage 85 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. factor listed in Table W-1A of this subpart shall b e used to estimate all streams of gases, including recycle CO 2 stream. The component count can be determined usin g either of the calculation methods described in this paragraph (r) (2) , except for miles of gathering pipelines, which must be determined using Component Count Meth od 2 in paragraph (r)(2)(ii) of this section . The same calculation method must be used for the entire calendar year. (i) Component Count Method 1. For all onshore petro leum and natural gas production operations and onshore petroleum and natural gas gathering and boosting operations in the facility perform the following activities: (A) Count all major equipment listed in Table W-1B and Table W-1C of this subpart. For meters/piping, use one meters/piping per well-pad. (B) Multiply major equipment counts by the average component counts listed in Table W-1B for onshore natural gas production and onshore petroleum and natural gas gathering and boosting; and Table W-1C of this subpart for onshore oil production. Use the appropriate factor in Table W-1A of this subpart for operations in Eas tern and Western U.S. according to the mapping in Table W-1D of this subpart. (ii) Component Count Method 2. Count each component individually for the facility. Use the appropriate factor in Table W-1A of this subpar t for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subp art. (3) Underground natural gas storage facilities must use the appropriate default total hydrocarbon population emission factors for storage wellheads in gas service listed in Table W-4 of this subpart. (4) LNG storage facilities must use the appropriate default methane population emission factor for LNG storage compressors in gas service l isted in Table W-5 of this subpart. Deleted: and W-1C of this subpart

Deleted: , respectivelyPage 86 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (5) LNG import and export facilities must use the a ppropriate default methane population emission factor for LNG terminal compressors in gas service listed in Table W-6 of this subpart. (6) Natural gas distribution facilities must use th e appropriate methane emission factors as described in paragraphs (r)(6)(i) and (ii) of th is section. (i) Below grade metering-regulating stations, distr ibution mains, and distribution services must use the appropriate default methane population emission factors listed in Table W-7 of this subpart. Below grade transmission-distribution tran sfer stations must use the emission factor for below grade metering-regulating stations. (ii) Above grade metering-regulating stations that are not above grade transmissiondistribution transfer stations must use the meter/r egulator run population emission factor calculated in Equation W-31. Natural gas distributi on facilities that do not have above grade transmission-distribution transfer stations are not required to calculate emissions for above grade metering-regulating stations and are not required t o report GHG emissions in § 98.236(r)(2)(v). (s) Offshore petroleum and natural gas production f acilities. Report CO 2 , CH 4 , and N 2 O emissions for offshore petroleum and natural gas pr oduction from all equipment leaks, vented emission, and flare emission source types as identi fied 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 BOEMRE jur isdiction shall report the same annual emissions as calculated and reported by BOEM RE 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 wit h the most recent BOEMRE emissions study publication year, report the most recent BOEM RE reported emissions data published by BOEMRE referenced in 30 CFR 250.302 through 304 (GO ADS). Adjust emissions based on thePage 87 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. operating time for the facility relative to the ope rating time in the most recent BOEMRE published study. (ii) [Reserved] (2) Offshore production facilities that are not und er BOEMRE jurisdiction must use the most recent monitoring methods and calculation meth ods published by BOEMRE referenced in 30 CFR 250.302 through 250.304 to calculate and rep ort annual emissions (GOADS). (i) For any calendar year that does not overlap wit h the most recent BOEMRE emissions study publication, you may report the most recently 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 operati ng time in the previous reporting period. (ii) [Reserved] (3) If BOEMRE discontinues or delays their data col lection 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 estimate emissi ons. 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 reporting, offshore facilities either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle must use the most recent BOEMRE data collection and emissions estimation methods published by BOEMRE referenced in 30 CFR 250.302 through 250. 304 to calculate and report emissions. (t) GHG volumetric emissions using actual condition s. If equation parameters in § 98.233 are already determined at standard conditions as pr ovided in the introductory text in § 98.233, which results in volumetric emissions at standard c onditions, then this paragraph does not apply.Page 88 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Calculate volumetric emissions at standard conditio ns 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 s tandard 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:

E s,n = Natural gas volumetric emissions at standard tem perature and pressure (STP) conditions in cubic feet, except E s,n equals FR s,p for each well p when calculating either subsonic or sonic flowrates unde r 98.233(g). E a,n = Natural gas volumetric emissions at actual condi tions in cubic feet, except

E a,n equals FR a,p for each well p when calculating either subsonic o r 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 p sia). P a = Absolute pressure at actual conditions (psia). Z a = Compressibility factor at actual conditions for natural gas. You may use

either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure con ditions. (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:Page 89 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. E s,i = GHG i volumetric emissions at standard temperatu re 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 p sia). P a = Absolute pressure at actual conditions (psia). Z a = Compressibility factor at actual conditions for GHG i. You may use either a

default compressibility factor of 1, or a site-spec ific compressibility factor based on actual temperature and pressure conditions

. (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 pa ragraphs (u)(1) and (2) of this section. (1) Estimate CH 4 and CO 2 emissions from natural gas emissions using Equatio n W-35 of this section.

i n s i s M E E *

, , = (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 con ditions in cubic feet. M i = Mole fraction of GHG i in the natural gas. (2) For Equation W-35 of this section, the mole fra ction, M i , shall be the annual average mole fraction for each sub-basin category or facili ty, as specified in paragraphs (u)(2)(i) through (vii) of this section.Page 90 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) GHG mole fraction in produced natural gas for o nshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering an d boosting 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 annu al average gas composition based on your most recent available analysis of the sub-basin cat egory or facility, as applicable to the emission

source. (ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the demethanizer or dew point control and GHG mole fracti on in facility specific residue gas to transmission pipeline systems for all emissions sou rces downstream of the de-methanizer overhead or dew point control for onshore natural g as processing facilities. For onshore natural gas processing plants that solely fractionate a liq uid stream, use the GHG mole percent in feed natural gas liquid for all streams. If you have a c ontinuous gas composition analyzer on feed natural gas, you must use these values for determin ing the mole fraction. If you do not have a continuous gas composition analyzer, then annual sa mples must be taken according to methods set forth in § 98.234(b). (iii) GHG mole fraction in transmission pipeline na tural gas that passes through the facility for the onshore natural gas transmission c ompression industry segment and the onshore natural gas transmission pipeline industry segment . You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for G HG mole fraction in natural gas or site specific engineering estimates based on best availa ble data. (iv) GHG mole fraction in natural gas stored in the underground natural gas storage industry segment. You may use either a default 95 p ercent methane and 1 percent carbon dioxidePage 91 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. fraction for GHG mole fraction in natural gas or si te specific engineering estimates based on best available data. (v) GHG mole fraction in natural gas stored in the LNG storage industry segment. You may use either a default 95 percent methane and 1 p ercent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineerin g estimates 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 fro m transmission pipelines, you may use either a default 95 percent methane and 1 percent carbon dio xide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data. (vii) GHG mole fraction in local distribution pipel ine natural gas that passes through the facility for natural gas distribution facilities. Y ou 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. (v) GHG mass emissions. Calculate GHG mass emission s in metric tons by converting the GHG volumetric emissions at standard conditions into mass emissions using Equation W-36 of this section.

3

, 

### 10 * * − 

### = i i s i 

### E Mass ρ (Eq. W-36)

Where:

Mass i = GHG i (either CH 4 , CO 2 , or N 2 O) mass emissions in metric tons. E s,i = GHG i (either CH 4 , CO 2 , or N 2 O) volumetric emissions at standard conditions,

in cubic feet. ρ 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.Page 92 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (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 volum e in cubic feet (including pipelines, manifolds and vessels) between isolation valves. (2) Retain logs of the number of blowdowns per cale ndar year. (3) Calculate the total annual CO 2 emissions from each EOR injection pump system using Equation W-37 of this section:

3 

### 10 * * * * − 

### = 2 2 CO

c v CO 

### GHG

R V N Mass (Eq. W-37)

Where:

Mass CO2 = Annual EOR injection pump system emissions in me tric tons from

blowdowns. N = Number of blowdowns for the EOR injection pump system in the calendar

year. V v = Total volume in cubic feet of EOR injection pump system chambers

(including pipelines, manifolds and vessels) betwee n isolation valves. R c = Density of critical phase EOR injection gas in k g/ft 3 . You may use an

appropriate standard method published by a consensu s-based standards organization if such a method exists or you may use an industry standard practice to determine density of super 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 operat ions as follows: (1) Determine the amount of CO 2 retained in hydrocarbon liquids after flashing in tankage at STP conditions. Annual samples of hydroc arbon liquids downstream of the storage tank must be taken according to methods set forth i n § 98.234(b) to determine retention of CO 2Page 93 of 192

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

hl hl CO V S Mass 2 * = (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 to ns. S hl = Amount of CO 2 retained in hydrocarbon liquids downstream of the storage

tank, in metric tons per barrel, under standard con ditions. 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 , onshore petroleum and natural gas gathering and boosting, and natural gas distribution combustion emissions. Calculate CO 2 , CH 4 , and N 2 O combustion-related emissions from stationary or p ortable equipment, except as specified in paragraph (z)(3) and (4) of this secti on, as follows: (1) If a fuel combusted in the stationary or portab le equipment is listed in Table C-1 of subpart C of this part, or is a blend containing on e 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 mini mum high heat value of 950 Btu per standard cubic foot, use the calculation method described in paragraph (z)(1)(i) of this section and you may use the emission factor provided for natural ga s 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,Page 94 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. process vent gas, or a blend containing field gas o r process vent gas, calculate emissions according to paragraph (z)(2) of this section. (i) For fuels listed in Table C-1 or a blend contai ning 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 requirem ents for that tier listed in § 98.33, any monitoring or QA/QC requirements listed for that ti er in § 98.34, any missing data procedures specified in 98.35, and any recordkeeping requireme nts specified in § 98.37. (ii) Emissions from fuel combusted in stationary or portable equipment at onshore natural gas and petroleum production facilities , onshore petroleum and natural gas gathering and boosting facilities, and at natural gas distribution facilities will be reported according to the requirements specified in § 98.236(z) and not accor ding to the reporting requirements specified in subpart C of this part. (2) For fuel combustion units that combust field ga s, 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 feet, calculate combustion emissions as follows: (i) You may use company records to determine the vo lume of fuel combusted in the unit during the reporting year. (ii) If you have a continuous gas composition analy zer 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 us e 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.Page 95 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iii) Calculate GHG volumetric emissions at actual conditions using Equations W-39A and W-39B of this section: 

# ∑

= 

### + = 5

1 

### * * * ) * ( j j j a CO a a,CO 

### R Y V Y V E 2

2 

### η (Eq. W-39A)



## ( )
4 4 CH

a a,CH Y V E *

1 * η

− = (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 cond itions. V a = Volume of gas sent to combustion unit in actual cubic feet, during the year. Y CO2 = 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 cond itions. η = Fraction of gas combusted for portable and stati onary equipment determined

using engineering estimation. For internal combusti on devices, a default of 0.995 can be used. Y j = 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 co nstituent j; 1 for methane,

2 for ethane, 3 for propane, 4 for butane, and 5 fo r pentanes plus, in gas sent to combustion unit. Y CH4 = 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 th is section. (vi) Calculate N 2 O mass emissions using Equation W-40 of this sectio n.



# ( ) EF

HHV Fuel Mass O N 2 

### ×

× × × = − 3 

### 10 1 (Eq. W-40)Page 96 of 192

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

Mass N2O = Annual N 2 O emissions from the combustion of a particular typ e of fuel

(metric tons). Fuel = Annual mass or volume of the fuel combusted (mass or volume per year,

choose appropriately to be consistent with the unit s of HHV). HHV = Higher heating value of fuel, mmBtu/unit of f uel (in units consistent with the fuel quantity combusted). For field gas or process vent gas, you may use either a default higher heating value of 1.235 × 10 −3 mmBtu/scf or a sitespecific higher heating value. For natural gas that is not of pipeline quality or that has a high heat value less than 950 Btu per st andard cubic foot, use a site-specific higher heating value. EF = Use 1.0 × 10 −4 kg N 2 O/mmBtu. 1 × 10 −3 = Conversion factor from kilograms to metric tons. (3) External fuel combustion sources with a rated h eat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the t ype and number of each external fuel combustion unit. (4) Internal fuel combustion sources, not compresso r-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 fu el combustion unit. § 98.234 Monitoring and QA/QC requirements. The GHG emissions data for petroleum and natural ga s emissions sources must be quality assured as applicable as specified in this section. Offshore petroleum and natural gas production facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 250.Page 97 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (a) You must use any of the methods described as fo llows in this paragraph to conduct leak detection(s) of equipment leaks and through-va lve leakage from all source types listed in § 98.233(k), (o), (p) and (q) that occur during a cal endar year. (1) Optical gas imaging instrument. Use an optical gas imaging instrument for equipment leak detection in accordance with 40 CFR part 60, s ubpart 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 dete ction sensitivity level of 60 grams per hour as stated in 40 CFR Part 60, subpart A, Table 1: De tection Sensitivity Levels; § 60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, a nd § 60.18(i)(2)(iv) and (v); § 60.18(i)(3); § 60.18(i)(4)(i) and (v); including the requirements for daily instrument checks and distances, and excluding requirements for video records. Any emiss ions 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 parame ters. Unless using methods in paragraph (a)(2) of this section, an optical gas imaging inst rument must be used for all source types that are inaccessible and cannot be monitored without elevat ing the monitoring personnel more than 2 meters above a support surface. (2) Method 21. Use the equipment leak detection met hods in 40 CFR part 60, appendix A-7, Method 21. If using Method 21 monitoring, if a n instrument reading of 10,000 ppm or greater is measured, a leak is detected. Inaccessib le emissions sources, as defined in 40 CFR part 60, are not exempt from this subpart. Owners or ope rators must use alternative leak detectionPage 98 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. devices as described in paragraph (a)(1) or (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 emissi ons detected by the infrared laser beam illuminated instrument is a leak unless screened wi th Method 21 monitoring, in which case 10,000 ppm or greater is designated a leak. In addi tion, you must operate the infrared laser beam illuminated instrument to detect the source types r equired by this subpart in accordance with the instrument manufacturer’s operating parameters. (4) [Reserved] (5) Acoustic leak detection device. Use the acousti c leak detection device to detect through-valve leakage. When using the acoustic leakdetection device to quantify the throughvalve leakage, you must use the instrument manufact urer’s calculation methods to quantify the through-valve leak. When using the acoustic leak de tection device, if a leak of 3.1 scf per hour or greater is calculated, a leak is detected. In addit ion, you must operate the acoustic leak detection device to monitor the source valves required by thi s subpart in accordance with the instrument manufacturer’s operating parameters. Acoustic steth oscope 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 throu gh-valve leakage is identified. Leaks are reported if a leak rate of 3.1 scf per hour or grea ter 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 methodPage 99 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. published by a consensus-based standards organizati on if such a method exists or you may use an industry standard practice. Consensus-based stan dards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the Ame rican Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). (c) Use calibrated bags (also known as vent bags) o nly where the emissions are at nearatmospheric pressures and below the maximum tempera ture specified by the vent bag manufacturer such that the bag is safe to handle. T he bag opening must be of sufficient size that the entire emission can be tightly encompassed for measurement till the bag is completely filled. (1) Hold the bag in place enclosing the emissions s ource to capture the entire emissions and record the time required for completely filling the bag. If the bag inflates 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 st andard conditions using calculations in § 98.233(t). (4) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natu ral 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 instruction s shall conduct measurements, including equipment manufacturer operating procedur es and measurement methods relevant toPage 100 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 atta chments available from the manufacturer, is not able to capture all the emissi ons 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. (3) Estimate natural gas volumetric emissions at st andard conditions using calculations in § 98.233(t). Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natu ral 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 m anufacturer’s instructions for calibration. (e) Peng Robinson Equation of State means the equat ion of state defined by Equation W41 of this section:

2 2 

### 2 b bV V a b V RT p

m

m m 

### −

+ −

− = α (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 .0Page 101 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. b =

c c

p RT 7780 .0

α = 

# ( ) 2 2 

### 1 26992 .0 54226 .1 37464 .0 1                

− − + +

c 

### T T ω ω

Where:

ω = Acentric factor of the species. T c = Critical temperature. P c = Critical pressure. (f) Special reporting provisions for best available monitoring methods in reporting year 2015—(1) Best available monitoring methods. From Ja nuary 1, 2015 to March 31, 2015, for a facility subject to this subpart, you must use the calculation methodologies and equations in § 98.233 “Calculating GHG Emissions”, but you may use the best available monitoring method for any parameter for which it is not reasonably feasib le to acquire, install, and operate a required piece of monitoring equipment by January 1, 2015 as specified in paragraphs (f)(2) and (3) of this section. Starting no later than April 1, 2015, you must discontinue using best available methods and begin following all applicable monitori ng and QA/QC requirements of this part, except as provided in paragraph (f)(4) of this sect ion. Best available monitoring methods means any of the following methods: (i) Monitoring methods currently used by the facili ty that do not meet the specifications of this subpart. (ii) Supplier data. (iii) Engineering calculations. (iv) Other company records.Page 102 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (2) Best available monitoring methods for well-rela ted measurement data. You may use best available monitoring methods for well-related measurement data identified in paragraphs (f)(2)(i) and (ii) of this section that cannot reas onably be measured according to the monitoring and QA/QC requirements of this subpart. (i) If Calculation Method 1 for liquids unloading i n § 98.233(f)(1) was used in calendar year 2014 and will be used again in calendar year 2 015, the vented natural gas flow rate for any well in a unique tubing diameter group and pressure group combination that has not been previously measured. (ii) If using Equation W-10A of this subpart to det ermine natural gas emissions from completions and workovers for representative wells, the initial and average flowback rates (when using Calculation Method 1 in § 98.233(g)(1)(i)) or pressures upstream and downstream of the choke (when using Calculation Method 2 in § 98.233( g)(1)(ii)) for any well in a well type combination that has not been previously measured. (3) Best available monitoring methods for emissions measurement. You may use best available monitoring methods for sources listed in paragraphs (f)(3)(i) and (ii) of this section if the required measurement data cannot reasonably be obtained according to the monitoring and QA/QC requirements of this part. (i) Centrifugal compressor as found measurements of manifolded emissions from groups of centrifugal compressor sources according to § 98 .233(o)(4) and (5), in onshore natural gas processing, onshore natural gas transmission compre ssion, 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).Page 103 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Reciprocating compressor as found measurements of manifolded emissions from groups of reciprocating compressor sources accordin g to § 98.233(p)(4) and (5), in onshore natural gas processing, onshore natural gas transmi ssion compression, underground natural gas storage, LNG storage, and LNG import and export equ ipment as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1). (4) Requests for extension of the use of best avail able monitoring methods beyond March 31, 2015. You may submit a request to the Administr ator to use one or more best available monitoring methods for sources listed in paragraphs (f)(2) and (3) of this section beyond March 31, 2015. (i) Timing of request. The extension request must b e submitted to EPA no later than January 31, 2015. (ii) Content of request. Requests must contain the following information: (A) A list of specific source types and parameters for which you are seeking use of best available monitoring methods. (B) For each specific source type for which you are requesting use of best available monitoring methods, a description of the reasons th at the needed equipment could not be obtained and installed before April 1, 2015. (C) A description of the specific actions you will take to obtain and install the equipment as soon as reasonably feasible and the expected dat e by which the equipment will be installed and operating. (iii) Approval criteria. To obtain approval to use best available monitoring methods after March 31, 2015, you must submit a request demonstra ting to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoringPage 104 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. equipment by April 1, 2015. The use of best availab le methods under paragraph (f) of this section will not be approved beyond December 31, 20 15. (g) Special reporting provisions for best available mon itoring methods in reporting year 2016

. (1) Best available monitoring methods. From January 1, 2016 to March 31, 2016, you must use the calculation methodologies and equation s in § 98.233 but you may use the best available monitoring method for any parameter for w hich it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2016 as specified in paragraphs (g)(2) through (5) of this section. Star ting no later than April 1, 2016, you must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as provided in paragraph (g)(6) of this section. Best available monitoring methods means any of the follo wing methods: (i) Monitoring methods currently used by the facili ty that do not meet the specifications of this subpart. (ii) Supplier data. (iii) Engineering calculations. (iv) Other company records. (2) Best available monitoring methods for well-rela ted measurement data for oil wells with hydraulic fracturing. You may use best availab le monitoring methods for any well-related measurement data that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart for venting during wel l completions and workovers of oil wells with hydraulic fracturing. Deleted: [Reserved]Page 105 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) Best available monitoring methods for onshore p etroleum and natural gas gathering and boosting facilities. You may use best available monitoring methods for any leak detection and/or measurement data that cannot reasonably be m easured according to the monitoring and QA/QC requirements of this subpart for acid gas rem oval vents as specified in § 98.233(d). (4) Best available monitoring methods for natural g as transmission pipelines. You may use best available monitoring methods for any measu rement data for natural gas transmission pipelines that cannot reasonably be obtained accord ing to the monitoring and QA/QC requirements of this subpart for blowdown vent stac ks. (5) Best available monitoring methods for specified activity data. You may use best available monitoring methods for activity data as l isted in paragraphs (g)(5)(i) through (iii) of this section that cannot reasonably be obtained acc ording to the monitoring and QA/QC requirements of this subpart for well completions a nd workovers of oil wells with hydraulic fracturing, onshore petroleum and natural gas gathe ring and boosting facilities, or natural gas transmission pipelines. (i) Cumulative hours of venting, days, or times of operation in § 98.233(e), (g), (o), (p), and (r). (ii) Number of blowdowns, completions, workovers, o r other events in § 98.233(g) and (i). (iii) Cumulative volume produced, volume input or o utput, or volume of fuel used in paragraphs § 98.233(d), (e), (j), (n), and (z). (6) Requests for extension of the use of best avail able monitoring methods beyond March 31, 2016. You may submit a request to the Administr ator to use one or more best availablePage 106 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. monitoring methods for sources listed in paragraphs (g)(2) through (5) of this section beyond March 31, 2016. (i) Timing of request. The extension request must b e submitted to EPA no later than January 31, 2016. (ii) Content of request. Requests must contain the following information: (A) A list of specific source types and parameters for which you are seeking use of best available monitoring methods. (B) For each specific source type for which you are requesting use of best available monitoring methods, a description of the reasons th at the needed equipment could not be obtained and installed before April 1, 2016. (C) A description of the specific actions you will take to obtain and install the equipment as soon as reasonably feasible and the expected dat e by which the equipment will be installed and operating. (iii) Approval criteria. To obtain approval to use best available monitoring methods after March 31, 2016, you must submit a request demonstra ting to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by April 1, 2016. The use of best availab le methods under this paragraph (g) will not be approved beyond December 31, 2016. (h) For well venting for liquids unloading, if a mo nitoring period other than the full calendar year is used to determine the cumulative a mount 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 num ber of unloading events per well (the term “V p ” in Equations W-8 and W-9 of § 98.233), then the m onitoring period must begin before February 1 of the reporting year and m ust not end before December 1 of thePage 107 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. reporting year. The end of one monitoring period mu st 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. Except as specified in § 98.233, whenever a value o f 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 or activi ty data are not collected), you must follow the procedures specified in paragraphs (a) through (i) of this section, as applicable. (a) For stationary and portable combustion sources that use the calculation methods of subpart C of this part, you must use the missing da ta procedures in subpart C of this part. (b) For each missing value of a parameter that shou ld have been measured quarterly or more frequently using equipment including, but not limited to, a continuous flow meter, composition analyzer, thermocouple, or pressure gau ge, you must substitute the arithmetic average of the quality-assured values of that param eter 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 a vailable prior to the missing data incident, you must use the first quality-assured value obtained a fter the missing data period as the substitute data value. A value is quality-assured according to the procedures specified in § 98.234. (c) For each missing value of a parameter that shou ld have been measured annually, you must repeat the estimation or measurement activity for those sources as soon as possible, including in the subsequent calendar year if missin g data are not discovered until after December 31 of the year in which data are collected, until v alid data for reporting are obtained. DataPage 108 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used for that subsequent year's emissions estimatio n. Where missing data procedures are used for the previous year, at least 30 days must separate e missions estimation or measurements for the previous year and emissions estimation or measureme nts for the current year of data collection. (d) For each missing value of a parameter that shou ld have been measured biannually (every two years), you must conduct the estimation or measurement activity for those sources as soon as possible in the subsequent calendar year if the estimation or measurement was not made in the appropriate year (first year of data collect ion and every two years thereafter), until valid data for reporting are obtained. Data developed and /or collected in a subsequent calendar year to substitute for missing data cannot be used to alter nate or postpone subsequent biannual emissions estimations or measurements. (e) For the first six months of required data colle ction, facilities that become newly subject to this subpart W may use best engineering estimates for any data that cannot reasonably be measured or obtained according to the requiremen ts of this subpart. (f) For the first six months of required data colle ction, facilities that are currently subject to this subpart W and that acquire new sources from another facility that were not previously subject to this subpart W may use best engineering estimates for any data related to those newly acquired sources that cannot reasonably be measured or obtained according to the requirements of this subpart. (g) Unless addressed in another paragraph of this s ection, for each missing value of any activity data, you must substitute data value(s) us ing the best available estimate(s) of the parameter(s), based on all applicable and available process or other data (including, but not limited to, processing rates, operating hours).Page 109 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 measured an d substitute values of a parameter, and the procedures used to substitute an unavailabl e value of a parameter per the requirements in § 98.236(bb). (i) You must follow recordkeeping requirements list ed in § 98.237(f). § 98.236 Data reporting requirements. In addition to the information required by § 98.3(c ), each annual report must contain reported emissions and related information as speci fied in this section. Reporters that use a flow or volume measurement system that corrects to stand ard conditions as provided in the introductory text in § 98.233 for data elements tha t are otherwise required to be determined at actual conditions, report gas volumes at standard c onditions rather the gas volumes at actual conditions and report the standard temperature and pressure used by the measurement system rather than the actual temperature and pressure. (a) The annual report must include the information specified in paragraphs (a)(1) through ( 10 ) of this section for each applicable industry segm ent. The annual report must also include annual emissions totals, in metric tons of each GHG , for each applicable industry segment listed in paragraphs (a)(1) through ( 10 ) of this section, and each applicable emission sou rce listed in paragraphs (b) through (z) of this section. (1) Onshore petroleum and natural gas production. F or the equipment/activities specified in paragraphs (a)(1)(i) through (xvii) of this sect ion, report the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices. Report the infor mation specified in paragraph (b) of this section. Deleted: 8

Deleted: 8Page 110 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph (c) of this section. (iii) Acid gas removal units. Report the informatio n specified in paragraph (d) of this section. (iv) Dehydrators. Report the information specified in paragraph (e) of this section. (v) Liquids unloading. Report the information speci fied in paragraph (f) of this section. (vi) Completions and workovers with hydraulic fract uring. Report the information specified in paragraph (g) of this section. (vii) Completions and workovers without hydraulic f racturing. 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 specified in paragraph (l) of this section. (x) Associated natural gas. Report the information 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 informati on specified in paragraph (o) of this section. (xiii) Reciprocating compressors. Report the inform ation specified in paragraph (p) of this section. (xiv) Equipment leaks by population count. Report t he information specified in paragraph (r) of this section.Page 111 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (xv) EOR injection pumps. Report the information sp ecified in paragraph (w) of this section. (xvi) EOR hydrocarbon liquids. Report the informati on specified in paragraph (x) of this section. (xvii) Combustion equipment. Report the information specified in paragraph (z) of this section. (2) Offshore petroleum and natural gas production. Report the information specified in paragraph (s) of this section. (3) Onshore natural gas processing. For the equipme nt/activities specified in paragraphs (a)(3)(i) through (vii) of this section, report the information specified in the applicable paragraphs of this section. (i) Acid gas removal units. Report the information specified in paragraph (d) of this section. (ii) Dehydrators. Report the information specified in paragraph (e) of this section. (iii) Blowdown vent stacks. Report the information 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 information specified in paragraph (o) of this section. (vi) Reciprocating compressors. Report the informat ion specified in paragraph (p) of this section. (vii) Equipment leak surveys. Report the informatio n specified in paragraph (q) of this section.Page 112 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (4) Onshore natural gas transmission compression. F or the equipment/activities specified in paragraphs (a)(4)(i) through (vii) of this secti on, report the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices. Report the infor mation specified in paragraph (b) of this section. (ii) Blowdown vent stacks. Report the information s pecified in paragraph (i) of this section. (iii) Transmission storage tanks. Report the inform ation 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 information specified in paragraph (o) of this section. (vi) Reciprocating compressors. Report the informat ion specified in paragraph (p) of this section. (vii) Equipment leak surveys. Report the informatio n specified in paragraph (q) of this section. (5) Underground natural gas storage. For the equipm ent/activities specified in paragraphs (a)(5)(i) through (vi) of this section, report the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices. Report the infor mation specified in paragraph (b) of this section. (ii) Flare stacks. Report the information specified in paragraph (n) of this section.Page 113 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iii) Centrifugal compressors. Report the informati on specified in paragraph (o) of this section. (iv) Reciprocating compressors. Report the informat ion specified in paragraph (p) of this section. (v) Equipment leak surveys. Report the information specified in paragraph (q) of this section. (vi) Equipment leaks by population count. Report th e information specified in paragraph (r) of this section. (6) LNG storage. For the equipment/activities speci fied in paragraphs (a)(6)(i) through (v) of this section, report the information specifi ed 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 informatio n specified in paragraph (o) of this section. (iii) Reciprocating compressors. Report the informa tion 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 equipm ent/activities specified in paragraphs (a)(7)(i) through (vi) of this section, report the information specified in the applicable paragraphs of this section.Page 114 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Blowdown vent stacks. Report the information sp ecified in paragraph (i) of this section. (ii) Flare stacks. Report the information specified in paragraph (n) of this section. (iii) Centrifugal compressors. Report the informati on specified in paragraph (o) of this section. (iv) Reciprocating compressors. Report the informat ion specified in paragraph (p) of this section. (v) Equipment leak surveys. Report the information specified in paragraph (q) of this section. (vi) Equipment leaks by population count. Report th e information specified in paragraph (r) of this section. (8) Natural gas distribution. For the equipment/act ivities specified in paragraphs (a)(8)(i) through (iii) of this section, report the informati on specified in the applicable paragraphs of this section. (i) Combustion equipment. Report the information sp ecified 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 t he information specified in paragraph (r) of this section. (9) Onshore petroleum and natural gas gathering and boosting. For the equipment/activities specified in paragraphs (a)(9) (i) through (xi) of this section, report the information specified in the applicable paragraphs of this section.Page 115 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Natural gas pneumatic devices. Report the infor mation 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 informatio n specified in paragraph (d) of this section. (iv) Dehydrators. Report the information specified in paragraph (e) of this section. (v) Blowdown vent stacks. Report the information sp ecified in paragraph (i) of this section. (vi) Storage tanks. Report the information specifie d in paragraph (j) of this section. (vii) Flare stacks. Report the information specifie d in paragraph (n) of this section. (viii) Centrifugal compressors. Report the informat ion specified in paragraph (o) of this section. (ix) Reciprocating compressors. Report the informat ion specified in paragraph (p) of this section. (x) Equipment leaks by population count. Report the information specified in paragraph (r) of this section. (xi) Combustion equipment. Report the information s pecified in paragraph (z) of this section. (10) Onshore natural gas transmission pipeline. For blowdown vent stacks, report the information specified in paragraph (i) of this sect ion. (b) Natural gas pneumatic devices. You must indicat e whether the facility contains the following types of equipment: continuous high bleed natural gas pneumatic devices, continuousPage 116 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. low bleed natural gas pneumatic devices, and interm ittent bleed natural gas pneumatic devices. If the facility contains any continuous high bleed nat ural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, or intermitten t bleed natural gas pneumatic devices, then you must report the information specified in paragr aphs (b)(1) through (4) of this section. (1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) and (ii) of this section. (i) The total number of devices of each type, deter mined according to § 98.233(a)(1) and (2). (ii) If the reported value in paragraph (b)(1)(i) o f this section is an estimated value determined according to § 98.233(a)(2), then you mu st report the information specified in paragraphs (b)(1)(ii)(A) through (C) of this sectio n. (A) The number of devices of each type reported in paragraph (b)(1)(i) of this section that are counted. A list of the well ID numbers associated with the devices that are counted (for the onshore petroleum and natural gas production indust ry segment only). (B) The number of devices of each type reported in paragraph (b)(1)(i) of this section that are estimated (not counted). A list of the well ID numbers associated with the devices that are estimated (not counted) (for the onshore petroleum and natural gas production industry segment only). (C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting. (2) For each type of pneumatic device, the estimate d average number of hours in the calendar year that the natural gas pneumatic device s reported in paragraph (b)(1)(i) of this section were operating in the calendar year (“T t ” in Equation W-1 of this subpart).Page 117 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 sub part 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 sub part and § 98.233(a)(4), and reported in paragraph (b)(1)(i) of this section. (c) Natural gas driven pneumatic pumps. You must in dicate 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 specifi ed in paragraphs (c)(1) through ( 5 ) of this section. (1) Count of natural gas driven pneumatic pumps. (2) A list of the well ID numbers associated with t he natural gas driven pneumatic pumps (for the onshore petroleum and natural gas producti on industry segment only). ( 3 ) Average estimated number of hours in the calendar year the pumps were operational (“T” in Equation W-2 of this subpart). ( 4 ) 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 (2). ( 5 ) 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 (2). (d) Acid gas removal units. You must indicate wheth er 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 remov al units that vent directly to the atmosphere, to Deleted: 4

Deleted: 2

Deleted: 3

Deleted: 4Page 118 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. a flare or engine, or to a sulfur recovery plant, t hen you must report the information specified in paragraphs (d)(1) and (2) of this section. (1) You must report the information specified in pa ragraphs (d)(1)(i) through (vi i ) of this section for each acid gas removal unit. (i) A unique name or ID number for the acid gas rem oval unit. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gatherin g and boosting industry segment s , a different name or ID may be used for a single a cid gas removal unit for each location it operates at in a given year. (ii) A list of the well ID numbers associated with the acid gas removal units (for the onshore petroleum and natural gas production indust ry segment only). (ii i ) Total feed rate entering the acid gas removal uni t, using a meter or engineering estimate based on process knowledge or best availab le data, in million cubic feet per year. (i v ) The calculation method used to calculate CO 2 emissions from the acid gas removal unit, as specified in § 98.233(d). (v) Whether any CO 2 emissions from the acid gas removal unit are recov ered 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 transferre d 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 under subpart PP of this part. (v i ) 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). Deleted: ii

Deleted: iPage 119 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (vi i ) Sub-basin ID that best represents the wells and/or equipment supplying gas to the unit (for the onshore petroleum and natural gas pro duction and the onshore petroleum and natural gas gathering and boosting industry segment s only). (2) You must report information specified in paragr aphs (d)(2)(i) through (iii) of this section, applicable to the calculation method repor ted in paragraph (d)(1)(iii) of this section, for each acid gas removal unit. (i) If you used Calculation Method 1 or Calculation 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 (B) of thi s 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 r emoval 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) of this sectio n. (A) Indicate 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-4 A 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 g as flow into the acid gas removal unit in cubicPage 120 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. feet at actual conditions; or total annual volume o f 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 (L) of this secti on, as applicable to the simulation software package used. (A) The name of the simulation software package use d. (B) Natural gas feed temperature, in degrees Fahren heit. (C) Natural gas feed pressure, in pounds per square inch. (D) Natural gas flow rate, in standard cubic feet p er minute. (E) Acid gas content of the feed natural gas, in mo le percent. (F) Acid gas content of the outlet natural gas, in mole percent. (G) Unit operating hours, excluding downtime for ma intenance 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) Dehydrators. You must indicate whether your fac ility contains any of the following equipment: glycol dehydrators with an annual averag e 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 dehydratorsPage 121 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. that use desiccant. If your facility contains any o f the equipment listed in this paragraph (e), then you must report the applicable information in parag raphs (e)(1) through (3). (1) For each glycol dehydrator that has an annual a verage 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 paragr aphs (e)(1)(i) through (x ix ) of this section for the dehydrator. (i) A unique name or ID number for the dehydrator. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gathering and boosting industry segment s , a different name or ID may be used for a single d ehydrator for each location it operates at in a given year. (ii) A list of well ID number(s) associated with th e dehydrators (for the onshore petroleum and natural gas production industry segme nt only). (ii i ) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, determined by engineering estimate based on best av ailable data. (i v ) Dehydrator feed natural gas water content, in pou nds per million standard cubic feet. (v) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet. (v i ) Dehydrator absorbent circulation pump type (e.g., natural gas pneumatic, air pneumatic, or electric). (vi i ) Dehydrator absorbent circulation rate, in gallons per minute. (vii i ) Type of absorbent (e.g., triethylene glycol (TEG) , diethylene glycol (DEG), or ethylene glycol (EG)). ( ix ) Whether stripper gas is used in dehydrator. (x) Whether a flash tank separator is used in dehyd rator. Deleted: viii

Deleted: ii

Deleted: i

Deleted: viii

Deleted: iPage 122 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (x i ) Total time the dehydrator is operating, in hours. (xi i ) Temperature of the wet natural gas, in degrees Fa hrenheit. (xii i ) Pressure of the wet natural gas, in pounds per sq uare inch gauge. (xi v ) Mole fraction of CH 4 in wet natural gas. (xv) Mole fraction of CO 2 in wet natural gas. (xv i ) Whether any dehydrator emissions are vented to a vapor recovery device. (xvi i ) Whether any dehydrator emissions are vented to a flare or regenerator firebox/fire tubes. If any emissions are vented to a flare or re generator firebox/fire tubes, report the information specified in paragraphs (e)(1)(xvi i )(A) through (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 i ) Whether any dehydrator emissions are vented to th e 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 repor t the information specified in paragraphs (e)(1)(xvii i )(A) and (B) of this section for those emissions fr om 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, if applicable, (e)(5). Deleted: ii

Deleted: iPage 123 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (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, if applicable, (e)(5). (xi x ) Sub-basin ID that best represents the wells and/or equipment supplying gas to the dehydrator (for the onshore petroleum and natural g as production and the onshore petroleum and natural gas gathering and boosting industry segment s only). (2) For glycol dehydrators with an annual average d aily natural gas throughput less than 0.4 million standard cubic feet per day (as specifi ed in § 98.233(e)(2)), you must report the information specified in paragraphs (e)(2)(i) throu gh (v i ) of this section for the entire facility. (i) The total number of dehydrators at the facility

. (ii) A list of the well ID numbers associated with the dehydrators at the facility (for the onshore petroleum and natural gas production indust ry segment only). (ii i ) Whether any dehydrator emissions were vented to a vapor recovery device. If any dehydrator emissions were vented to a vapor recover y device, then you must report the total number of dehydrators at the facility that vented t o a vapor recovery device. For the onshore petroleum and natural gas production industry segme nt only, also report a list of the associated well ID numbers. (i v ) Whether any dehydrator emissions were vented to a control device other than a vapor recovery device or a flare or regenerator firebox/f ire tubes. If any dehydrator emissions were vented to a control device(s) other than a vapor re covery device or a flare or regenerator firebox/fire tubes, then you must specify the type of control device(s) and the total number of dehydrators at the facility that were vented to eac h type of control device. For the onshore Deleted: vii

Deleted: iiPage 124 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. petroleum and natural gas production industry segme nt only, also report a list of the associated well ID numbers for each type of control device. (v) Whether any dehydrator emissions were vented to a flare or regenerator firebox/fire tubes. If any dehydrator emissions were vented to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragr aphs (e)(2)(v)(A) through (D) of this section. (A) The total number of dehydrators venting to a fl are 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). (v i ) For dehydrator emissions that were not vented to a flare or regenerator firebox/fire tubes, report the information specified in paragrap hs (e)(2)(v i )(A) and (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 tha t were not vented to a flare or regenerator firebox/fire tubes, calculated according to § 98.23 3(e)(2), (e)(4), and, if applicable, (e)(5), where emissions are added together for all such dehydrato rs. (B) Annual CH 4 emissions, in metric tons CH 4 , for emissions from all dehydrators reported in paragraph (e)(2)(i) of this section tha t were not vented to a flare or regenerator firebox/fire tubes, calculated according to § 98.23 3(e)(2), (e)(4), and, if applicable, (e)(5), where emissions are added together for all such dehydrato rs. Deleted: i

Deleted: i Deleted: iPage 125 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) For dehydrators that use desiccant (as specifie d in § 98.233(e)(3)), you must report the information specified in paragraphs (e)(3)(i) t hrough (iii) of this section for the entire facilit y. (i) The same information specified in paragraphs (e )(2)(i) through (v) of this section for glycol dehydrators, and report the information unde r 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 t his section that are not venting to a flare or regenerator firebox/fire tubes, calculated accordin g to § 98.233(e)(3), (e)(4), and, if applicable, (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 or regenerator firebox/fire tubes, calculated accordin g to § 98.233(e)(3), (e)(4), and, if applicable, (e)(5), and summing for all such dehydrators. (f) Liquids unloading. You must indicate whether we ll venting for liquids unloading occurs at your facility, and if so, which methods ( as specified in § 98.233(f)) were used to calculate emissions. If your facility performs well venting for liquids unloading and uses Calculation Method 1, then you must report the info rmation specified in paragraph (f)(1) of this section. If the facility performs liquids unloading and uses Calculation Method 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 group for which you used Calculation Method 1 to calculate natural gas emiss ions from well venting for liquids unloading, report the information specified in paragraphs (f)( 1)(i) through (xii) of this section. Report information separately for wells with plunger lifts and wells without plunger lifts. Deleted: iPage 126 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Sub-basin ID. (ii) Well tubing diameter and pressure group ID and a list of the well ID numbers associated with each sub-basin well tubing diameter and pressure group ID

. (iii) Plunger lift indicator. (iv) Count of wells vented to the atmosphere for th e sub-basin/well tubing diameter and
pressure group. (v) Percentage of wells for which the monitoring pe riod used to determine the cumulative amount of time venting was not the full calendar ye ar. (vi) Cumulative amount of time wells were vented (s um 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 t ubing diameter and pressure group. (viii) Annual natural gas emissions, in standard cu bic 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 pressu re group combination, you must report the information specified in paragraphs (f)( 1)(xi)(A) through (E) of this section for each individual well not using a plunger lift that was t ested during the year. (A) Well ID n umber of tested well. (B) Casing pressure, in pounds per square inch abso lute. Deleted: API Deleted: NPage 127 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (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 press ure group combination, you must report the information specified in paragraphs (f)( 1)(xii)(A) through (E) of this section for each individual well using a plunger lift that was teste d during the year. (A) Well ID n umber of tested well. (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. (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 Calculati on 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 (x) of this section. Report information separately for each calculation method. (i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin

. (ii) Calculation method. (iii) Plunger lift indicator. (iv) Number of wells vented to the atmosphere. (v) Cumulative number of unloadings vented to the a tmosphere for each well, aggregated across all wells. Deleted: API Deleted: NPage 128 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (vi) Annual natural gas emissions, in standard cubi c feet, from well venting for liquids unloading, calculated according to § 98.233(f)(2) o r § 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 average i nternal casing diameter, in inches. (x) For wells with plunger lifts, the average inter nal tubing diameter, in inches. (g) Completions and workovers with hydraulic fractu ring. You must indicate whether your facility had any well completions or workovers with hydraulic fracturing during the calendar year. If your facility had well completion s or workovers with hydraulic fracturing during the calendar year, then you must report info rmation specified in paragraphs (g)(1) through (10) of this section, for each sub-basin and well t ype combination. Report information separately for completions and workovers. (1) Sub-basin ID and a list of the well ID numbers associated with each sub-basin that had completions or workovers with hydraulic fractur ing during the calendar year

. (2) Well type combination (horizontal or vertical, gas well or oil well)

. (3) Number of completions or workovers in the sub-b asin and well type combination 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 paragr aphs (g)(5)(i) and (ii) of this section. Deleted: gas

Deleted: gasPage 129 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Cumulative gas flowback time, in hours, from wh en gas is first detected until sufficient quantities are present to enable separat ion, and the cumulative flowback time, in hours, after sufficient quantities of gas are present to e nable separation (sum of “T p,i ” and sum of “T p,s ” values used in Equation W-10A). You may delay the r eporting of this data element if you indicate in the annual report that wildcat wells an d/or delineation wells are the only wells included in this number. If you elect to delay repo rting of this data element, you must report by the date specified in § 98.236(cc) the total number of hours of flowback from all wells during completions or workovers and the w ell ID n umber(s) for the well(s) included in the number. (ii) For the measured well(s), the flowback rate, i n standard cubic feet per hour, for each sub-basin (average of “FR s,p ” values in Equation W-12A), and the well ID numbers of the wells for which it is measured . You may delay the reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that can be used for the measurement. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured flowback rat e during well completion or workover and the w ell ID n umber(s) for the well(s) included in the measuremen t. (iii) If you used Equation W-12C to calculate the a verage gas production rate for an oil well, then you must report the information specifie d in paragraphs (g)(5)(iii)(A) and (B) of this section. (A) Gas to oil ratio for the well in standard cubic feet of gas per barrel of oil (“GOR p ” in Equation W-12C). (B) Volume of oil produced during the first 30 days of production after completions of each newly drilled well or well workover using hydr aulic fracturing, in barrels (“V p ” in Equation W-12C). Deleted: API W Deleted: N

Deleted: API W Deleted: NumberPage 130 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (6) If you used Equation W-10B to calculate annual volumetric total gas emissions for completions that vent gas to the atmosphere, then y ou must report the information specified in paragraphs (g)(6)(i) through (ii i ) of this section. (i) Vented natural gas volume, in standard cubic fe et, for each well in the sub-basin (“FV s,p ” in Equation W-10B). (ii) Flow rate at the beginning of the period of ti me when sufficient quantities of gas are present to enable separation, in standard cubic fee t per hour, for each well in the sub-basin (“FR p,i ” in Equation W-10B). (iii) The well ID number for which vented natural g as volume was measured. (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 fra cturing. You must indicate whether the facility had any gas well completions without h ydraulic fracturing or any gas well workovers without hydraulic fracturing, and if the activities occurred with or without flaring. If the facility had gas well completions or workovers without hydra ulic fracturing, then you must report the information specified in paragraphs (h)(1) through (4) of this section, as applicable. (1) For each sub-basin with gas well completions wi thout hydraulic fracturing and without flaring, report the information specified i n paragraphs (h)(1)(i) through (vi) of this section. Deleted: andPage 131 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin without hydraulic fracturing and without flaring

. (ii) Number of well completions that vented gas dir ectly to the atmosphere without flaring. (iii) Total number of hours that gas vented directl y to the atmosphere during venting 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 comp letions without hydraulic fracturing in the sub-basin without flaring, in standard cubic fe et per hour (average of all “V p ” used in Equation W-13B). You may delay reporting of this da ta element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that can be used for the measurement. If you elect to delay reporting of thi s data element, you must report by the date specified in § 98.236(cc) the measured average dail y gas production rate for all wells during completions and the well ID n umber(s) for the well(s) included in the measuremen t. (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 d irectly to the atmosphere, converted to mass emissions acco rding 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 d irectly to the atmosphere, converted to mass emissions acco rding to § 98.233(h)(1)). (2) For each sub-basin with gas well completions wi thout hydraulic fracturing and with flaring, report the information specified in paragr aphs (h)(2)(i) through (vii) of this section. Deleted: API Deleted: NPage 132 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin without hydraulic fracturing and with flaring

. (ii) Number of well completions that flared gas. (iii) Total number of hours that gas vented to a fl are during venting for all completions in the sub-basin category (the sum of all “T p ” for completions that vented to a flare from Equat ion W-13B). (iv) Average daily gas production rate for all comp letions 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). You may delay reporting of this data elemen t if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that can be used for the measurement. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average daily gas productio n rate for all wells during completions and the w ell ID n umber(s) for the well(s) included in the measuremen t. (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 with out hydraulic fracturing and without flaring, report the information specified in paragr aphs (h)(3)(i) through (iv) of this section. (i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin without hydraulic fracturing and without flaring

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This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Number of workovers that vented gas to the atm osphere 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 mass emiss ions 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 mass emiss ions as specified in § 98.233(h)(1)). (4) For each sub-basin with gas well workovers with out hydraulic fracturing and with flaring, report the information specified in paragr aphs (h)(4)(i) through (v) of this section. (i) Sub-basin ID and a list of well ID numbers associated with each sub-basin without hydraulic fracturing and with flaring

. (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 § 98.23 3(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 or event type or by using f low meters or a combination of both. If you calculated emissions by equipment or event type for any blowdown vent stacks, then you must report the information specified in paragraph (i)(1 ) of this section considering, in aggregate, allPage 134 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. blowdown vent stacks for which emissions were calcu lated by equipment or event type. If you calculated emissions using flow meters for any blow down vent stacks, then you must report the information specified in paragraph (i)(2) of this s ection considering, in aggregate, all blowdown vent stacks for which emissions were calculated usi ng flow meters. For the onshore natural gas transmission pipeline segment, you must also report the information in paragraph (i)(3) of this section. (1) Report by equipment or event type. If you calcu lated emissions from blowdown vent stacks by the seven categories listed in § 98.233(i )(2), then you must report the equipment or event types and the information specified in paragr aphs (i)(1)(i) through (iii) of this section for each equipment or event type. If a blowdown event r esulted in emissions from multiple equipment types, and the emissions cannot be apport ioned to the different equipment types, then you may report the information in paragraphs (i)(1) (i) through (iii) of this section for the equipment type that represented the largest portion of the emissions for the blowdown event. (i) Total number of blowdowns in the calendar year for the equipment or event 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 or event type). (ii) Annual CO 2 emissions for the equipment or event type, in metr ic tons CO 2 , calculated according to § 98.233(i)(2)(iii). (iii) Annual CH 4 emissions for the equipment or event type, in metr ic 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 (ii) of this section fo r the facility.Page 135 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) Annual CO 2 emissions from all blowdown vent stacks at the fac ility for which emissions were calculated using flow meters, in met ric 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 fac ility for which emissions were calculated using flow meters, in met ric tons CH 4 , (the sum of all CH 4 mass emission values calculated according to § 98.233(i) (3), for all flow meters). (3) Onshore natural gas transmission pipeline segme nt. Report the information in paragraphs (i)(3)(i) to (i)(3)(iii) for each separa te transmission pipeline blowdown event. (i) Annual CO 2 emissions in metric tons CO 2 . (ii) Annual CH 4 emissions in metric tons CH 4 . (iii) The location of the blowdown, in latitude and longitude in decimal degree format provided as a comma-delimited “latitude, longitude” coordinate pair reported in decimal degrees to at least four digits to the right of the decimal point. (j) Onshore production and onshore petroleum and natural gas gathering and boosting storage tanks. You must indicate whether your facil ity 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 emi ssions, and you must report the information specified in paragraphs (j)(1) and (2) of this section as applicable. If you used Calculation Method 1 or Calculation Method 2, and a ny 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 paragraph (j)(3) of this section.Page 136 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 spe cified in paragraphs (j)(1)(i) through (xv) of this section for each sub-basin and by calculation method. Onshore petroleum and natural gas gathering and boosting facilities do not report the information specified in paragraph (j)(1)(xiii) of this section. (i) Sub-basin ID. (ii) A list of the well ID number(s) associated wit h the tanks that controlled emissions with flares (for the onshore petroleum and natural gas production industry segment only). (iii) A list of the well ID number(s) associated wi th the tanks that did not control emissions with flares (for the onshore petroleum an d natural gas production industry segment only). (i v ) Calculation method used, and name of the software package used if using Calculation Method 1. ( v ) The total annual oil volume from gas-liquid separ ators and direct from wells that is sent to applicable onshore production and onshore petroleum and natural gas gathering and boosting storage tanks, in barrels. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delinea tion wells are the only wells in the sub-basin flowing to gas-liquid separators or direct to stora ge tanks. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the total volume of oil from all wells and the w ell ID n umber(s) for the well(s) included in this volume. (v i ) The average gas-liquid separator temperature, in degrees Fahrenheit. (v ii ) The average gas-liquid separator pressure, in pou nds per square inch gauge. (vi ii ) The average sales oil or stabilized oil API gravi ty, in degrees. Deleted: i

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This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. ( ix ) The minimum and maximum concentration (mole fract ion) of CO 2 in flash gas from onshore production and onshore natural gas gathering and boosting storage tanks. ( x ) The minimum and maximum concentration (mole fract ion) of CH 4 in flash gas from onshore production and onshore petroleum and natural gas gathering and boosting storage tanks. (x i ) The number of wells sending oil to gas-liquid sep arators or directly to atmospheric tanks. (x ii ) The number of atmospheric tanks. (xi ii ) An estimate of the number of atmospheric tanks, n ot on well-pads, receiving your oil. (xi v ) If any emissions from the atmospheric tanks at yo ur facility were controlled with vapor recovery systems, then you must report the in formation specified in paragraphs (j)(1)(xi v )(A) through (E) of this section. (A) The number of atmospheric tanks that control em issions 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. Deleted: vii

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This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (x v ) If any atmospheric tanks at your facility vented gas directly to the atmosphere without using a vapor recovery system or without fl aring, then you must report the information specified in paragraphs (j)(1)(x v )(A) through (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. (xv i ) If you controlled emissions from any atmospheric tanks at your facility with one or more flares, then you must report the information s pecified in paragraphs (j)(1)(x v i)(A) through (D) of this section. (A) The number of atmospheric tanks that controlled emissions with flares. (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 G HG emissions, then you must report the information specified in paragraphs (j)(2)(i) t hrough (iii) of this section. (i) Report the information specified in paragraphs (j)(2)(i)(A) through (F) of this section, at the basin level, for atmospheric tanks where emi ssions were calculated using Calculation Deleted: iii

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This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Method 3. Onshore gathering and boosting facilities do not r eport the information specified in paragraphs (j)(2)(i)(E) and (F) of this section. (A) The total annual oil /condensate throughput that is sent to all atmospheric tanks i n the basin, in barrels. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and delineation wells are the only wells in the sub-basin with oil production less than 10 barrels per day and that se nd oil to atmospheric tanks. If you elect to delay reporting of this data element, you must repo rt by the date specified in § 98.236(cc) the total annual oil throughput from all wells and the w ell ID n umber(s) for the well(s) included in this volume. (B) An estimate of the fraction of oil /condensate throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric ta nks in the basin that controlled emissions with flares. (C) An estimate of the fraction of oil /condensate throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric ta nks 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 separato rs (“Count” from Equation W-15 of this subpart) in the basin. (ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (D) of this section for each sub-basin with atmospheric tanks whose emi ssions were calculated using Calculation Method 3 and that did not control emissions with fl ares. Deleted: API W Deleted: NPage 140 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (A) Sub-basin ID. (B) The number of atmospheric tanks in the sub-basi n that did not control emissions with flares , and for the onshore petroleum and natural gas pro duction industry segment only, a list of the well ID numbers of the associated wells

. (C) Annual CO 2 emissions, in metric tons CO 2 , from atmospheric tanks in the sub-basin that did not control emissions with flares, calcula ted using Equation W-15 of this subpart and adjusted for vapor recovery, if applicable. (D) Annual CH 4 emissions, in metric tons CH 4 , from atmospheric tanks in the sub-basin that did not control emissions with flares, calcula ted using Equation W-15 of this subpart and adjusted for vapor recovery, if applicable. (iii) Report the information specified in paragraph s (j)(2)(iii)(A) through (E) of this section for each sub-basin with atmospheric tanks w hose 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-basi n that controlled emissions with flares , and for the onshore petroleum and natural gas pro duction industry segment only, a list of the well ID numbers of the associated wells

. (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 141 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) If you used Calculation Method 1 or Calculation Method 2, and 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 (iv) of this section for each subbasin. (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 s eparators did not close properly in the calendar year, in hours (sum of the “T n ” values used 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 c alendar 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 during t he calendar year, calculated using Equation W16 of this subpart. (k) Transmission storage tanks. You must indicate w hether 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 paragr aphs (k)(1) through (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 (iv) of this section. (i) The unique name or ID number for the transmissi on storage tank vent stack. (ii) Method used to determine if dump valve leakage occurred.Page 142 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iii) Indicate whether scrubber dump valve leakage occurred for the transmission storage tank vent according to § 98.233(k)(2). (iv) Indicate if there is a flare attached to the t ransmission storage tank vent stack. (2) If scrubber dump valve leakage occurred for a t ransmission storage tank vent stack, as reported in paragraph (k)(1)(iii) of this section, and the vent stack vented directly to the atmosphere during the calendar year, then you must report the information specified in paragraphs (k)(2)(i) through (v) of this section fo r 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 c ontinuous flow measurement device), in standard cubic feet per hour. (iii) Duration of time that the leak is counted as having occurred, in hours, as determined in § 98.233(k)(3) (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 (4). (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 (4). (3) If scrubber dump valve leakage occurred for a t ransmission storage tank vent stack, as reported in paragraph (k)(1)(iii), and the vent sta ck vented to a flare during the calendar year, then you must report the information specified in p aragraphs (k)(3)(i) through (vi) of this section. (i) Method used to measure the leak rate.Page 143 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (ii) Measured leakage rate (average leak rate from a continuous flow measurement device) in standard cubic feet per hour. (iii) Duration of time that flaring occurred in hou rs, as defined in § 98.233(k)(3) (may use best available data if a continuous flow measuremen t device was used). (iv) Annual CO 2 emissions, in metric tons CO 2 , that resulted from flaring gas, calculated according to § 98.233(k)(5). (v) Annual CH 4 emissions, in metric tons CH 4 , that resulted from flaring gas, calculated according to § 98.233(k)(5). (vi) Annual N 2 O emissions, in metric tons N 2 O, that resulted from flaring gas, calculated according to § 98.233(k)(5). (l) Well testing. You must indicate whether you per formed gas well or oil well testing, and if the testing of gas wells or oil wells result ed in vented or flared emissions during the calendar year. If you performed well testing that r esulted in vented or flared emissions during the calendar year, then you must report the information specified in paragraphs (l)(1) through (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 are not vented to a flare, then you must report the information specified in paragraphs (l)(1)(i) t hrough (vi i ) of this section. (i) Number of wells tested in the calendar year. (ii) Well ID numbers for the wells tested in the ca lendar year. (ii i ) Average number of well testing days per well for well(s) tested in the calendar year. (i v ) Average gas to oil ratio for well(s) tested, in c ubic feet of gas per barrel of oil. Deleted: iiPage 144 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (v) Average flow rate for well(s) tested, in barrel s of oil per day. You may delay reporting of this data element if you indicate in t he annual report that wildcat wells and/or delineation wells are the only wells that are teste d. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average flow rate for well(s) tested and the w ell ID n umber(s) for the well(s) included in the measuremen t. (v i ) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(l). (vi i ) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(l). (2) If you used Equation W-17A to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are vented to a flare, then you must report the information specified in paragraphs (l)(2)(i) throu gh (vii i ) of this section. (i) Number of wells tested in the calendar year. (ii) Well ID numbers for the wells tested in the ca lendar year. (ii i ) Average number of well testing days per well for well(s) tested in the calendar year. (i v ) Average gas to oil ratio for well(s) tested, in c ubic feet of gas per barrel of oil. (v) Average flow rate for well(s) tested, in barrel s of oil per day. You may delay reporting of this data element if you indicate in t he annual report that wildcat wells and/or delineation wells are the only wells that are teste d. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average flow rate for well(s) tested and the w ell ID n umber(s) for the well(s) included in the measuremen t. (v i ) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(l). (vi i ) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(l). (vii i ) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98.233(l). Deleted: i

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This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (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 (v i ) of this section. (i) Number of wells tested in the calendar year. (ii) Well ID numbers for the wells tested in the ca lendar year. (ii i ) Average number of well testing days per well for well(s) tested in the calendar year. (i v ) Average annual production rate for well(s) tested , in actual cubic feet per day. You may delay reporting of this data element if you ind icate in the annual report that wildcat wells and/or delineation wells are the only wells that ar e tested. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average annual production rate for well(s) tested and the w ell ID n umber(s) for the well(s) included in the

measurement. (v) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(l). (v i ) 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 were vented to a flare, then you must report the information specified in paragraphs (l)(4)(i) t hrough (vi i ) of this section. (i) Number of wells tested in calendar year. (ii) Well ID numbers for the wells tested in the ca lendar year. (ii i ) Average number of well testing days per well for well(s) tested in the calendar year. (i v ) Average annual production rate for well(s) tested , in actual cubic feet per day. You may delay reporting of this data element if you ind icate in the annual report that wildcat wells and/or delineation wells are the only wells that ar e tested. If you elect to delay reporting of this Deleted: ii

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This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. data element, you must report by the date specified in § 98.236(cc) the measured average annual production rate for well(s) tested and the w ell ID n umber(s) for the well(s) included in the

measurement

. (v) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(l). (v i ) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(l). (vi i ) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98.233(l). (m) Associated natural gas. You must indicate wheth er 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 p aragraphs (m)(1) through (8) of this section for each sub-basin. (1) Sub-basin ID and a list of well ID numbers for wells in each su b-basin for which associated gas was vented or flared

. (2) Indicate whether any associated gas was vented directly to the atmosphere without flaring. (3) Indicate whether any associated gas was flared. (4) Average gas to oil ratio, in standard cubic fee t 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 cale ndar 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). You may delay reporting of this data elem ent if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells from which associated gas was vented or flared. If you elect to delay reporting of this data element, you must report by the date Deleted: API W Deleted: N

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This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. specified in § 98.236(cc) the volume of oil produce d for well(s) with associated gas venting and flaring and the w ell ID n umber(s) for the well(s) included in the measuremen t. (6) Total volume of associated gas sent to sales, i n 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 § 98.233(m)). You may dela y reporting of this data element if you indicate in the annual report that wildcat wells an d/or delineation wells from which associated gas was vented or flared. If you elect to delay rep orting of this data element, you must report by the date specified in § 98.236(cc) the measured tot al volume of associated gas sent to sales for well(s) with associated gas venting and flaring and the w ell ID n umber(s) for the well(s) included in the measurement. (7) If you had associated gas emissions vented dire ctly to the atmosphere without flaring, then you must report the information specified in p aragraphs (m)(7)(i) through (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 and a list of their well ID numbers

. (ii) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(m)(3) and (4). (iii) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(m)(3) and (4). (8) If you had associated gas emissions that were f lared, then you must report the information specified in paragraphs (m)(8)(i) throu gh (iv) of this section for each sub-basin. (i) Total number of wells for which associated gas was flared and a list of their well ID numbers

. Deleted: API W Deleted: Deleted: N

Deleted: API W Deleted: NPage 148 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 , 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 facilit y contains any flare stacks. You must report the information specified in paragraphs (n)( 1) through (1 3 ) of this section for each flare stack at your facility, and for each industry segme nt applicable to your facility. (1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segment s , 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 continuo us flow measurement device. (3) Indicate whether the flare stack has a continuo us gas composition analyzer on feed gas to the flare. (4) Volume of gas sent to the flare, in standard cu bic feet (“V s ” in Equations W-19 and W-20 of this subpart). (5) Fraction of the feed gas sent to an un-lit flar e (“Z u ” in Equation W-19 of this subpart). (6) Flare combustion efficiency, expressed as the f raction 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). Deleted: 2Page 149 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (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 em issions 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. (13) For the onshore petroleum and natural gas prod uction industry segment, a list of the well ID numbers associated with flare stacks in eac h sub-basin. (o) Centrifugal compressors. You must indicate whet her your facility has centrifugal compressors. You must report the information specif ied in paragraphs (o)(1) and (2) of this section for all centrifugal compressors at your fac ility. For each compressor source or manifolded group of compressor sources that you con duct as found leak measurements as specified in § 98.233(o)(2) or (4), you must report the information specified in paragraph (o)(3) of this section. For each compressor source or mani folded group of compressor sources that you conduct continuous monitoring as specified in § 98. 233(o)(3) or (5), you must report the information specified in paragraph (o)(4) of this s ection. Centrifugal compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering an d boosting are not required to report information in paragrap hs (o)(1) through (4) of this section and instead must report the information specified i n paragraph (o)(5) of this section. (1) Compressor activity data. Report the informatio n specified in paragraphs (o)(1)(i) through (xiv) of this section for each centrifugal compressor located at your facility. (i) Unique name or ID for the centrifugal compresso r. (ii) Hours in operating-mode. (iii) Hours in not-operating-depressurized-mode.Page 150 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iv) Indicate whether the compressor was measured i n operating-mode. (v) Indicate whether the compressor was measured in not-operating-depressurized-mode. (vi) Indicate which, if any, compressor sources are part of a manifolded group of
compressor sources. (vii) Indicate which, if any, compressor sources ar e routed to a flare. (viii) Indicate which, if any, compressor sources h ave vapor recovery. (ix) Indicate which, if any, compressor source emis sions are captured for fuel use or are routed to a thermal oxidizer. (x) Indicate whether the compressor has blind flang es installed and associated dates. (xi) Indicate whether the compressor has wet or dry seals. (xii) If the compressor has wet seals, the number o f wet seals. (xiii) Power output of the compressor driver (hp). (xiv) Indicate whether the compressor had a schedul ed depressurized shutdown during the reporting year. (2) Compressor source. (i) For each compressor sour ce at each compressor, report the information specified in paragraphs (o)(2)(i)(A) th rough (C) of this section. (A) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(i) of this section. (B) Centrifugal compressor source (wet seal, isolat ion valve, or blowdown valve). (C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the sam e leak or vent ID for each compressor source in the manifolded group. If multiple compres sor sources are released through a single vent for which continuous measurements are used, us e the same leak or vent ID for eachPage 151 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. compressor source released via the measured vent. F or a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source. (ii) For each leak or vent, report the information specified in paragraphs (o)(2)(ii)(A) through (E) of this section. (A) Indicate whether the leak or vent is for a sing le compressor source or manifolded group of compressor sources and whether the emissio ns from the leak or vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery. (B) Indicate whether an as found measurement(s) as identified in § 98.233(o)(2) or (4) was conducted on the leak or vent. (C) Indicate whether continuous measurements as ide ntified in § 98.233(o)(3) or (5) were conducted on the leak or vent. (D) Report emissions as specified in paragraphs (o) (2)(ii)(D)(1) and (2) of this section for the leak or vent. If the leak or vent is routed to a flare, combustion, or vapor recovery, you are not required to report emissions under this paragra ph. (1) Annual CO 2 emissions, in metric tons CO 2 . (2) Annual CH 4 emissions, in metric tons CH 4 . (E) If the leak or vent is routed to flare, combust ion, or vapor recovery, report the percentage of time that the respective device was o perational when the compressor source emissions were routed to the device. (3) As found measurement sample data. If the measur ement methods specified in § 98.233(o)(2) or (4) are conducted, report the infor mation specified in paragraph (o)(3)(i) of this section. If the calculation specified in § 98.233(o )(6)(ii) is performed, report the information specified in paragraph (o)(3)(ii) of this section.Page 152 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i) For each as found measurement performed on a le ak or vent, report the information specified in paragraphs (o)(3)(i)(A) through (F) of this section. (A) Name or ID of leak or vent. Use same leak or ve nt ID as in paragraph (o)(2)(i)(C) of this section. (B) Measurement date. (C) Measurement method. If emissions were not detec ted when using a screening method, report the screening method. If emissions w ere detected using a screening method, report only the method subsequently used to measure the volumetric emissions. (D) Measured flow rate, in standard cubic feet per hour. (E) For each compressor attached to the leak or ven t, report the compressor mode during which the measurement was taken. (F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comin gling with non-compressor emission sources. (ii) For each compressor mode-source combination wh ere a reporter emission factor as calculated in Equation W-23 was used to calculate e missions in Equation W-22, report the information specified in paragraphs (o)(3)(ii)(A) t hrough (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 s,m

in Equation W-23). (C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the p receding two reporting years (Count m in Equation W-23).Page 153 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (D) Indicate whether the compressor mode-source com bination reporter emission factor is facility-specific or based on all of the reporte r’s applicable facilities. (4) Continuous measurement data. If the measurement methods specified in § 98.233(o)(3) or (5) are conducted, report the infor mation specified in paragraphs (o)(4)(i) through (iv) of this section for each continuous me asurement conducted on each leak or vent associated with each compressor source or manifolde d group of compressor sources. (i) Name or ID of leak or vent. Use same leak or ve nt ID as in paragraph (o)(2)(i)(C) of this section. (ii) Measured volume of flow during the reporting y ear, in million standard cubic feet. (iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 9 8.233(o)(3)(ii) and (o)(5)(iii). (iv) If the measurement is for a manifolded group o f compressor sources, indicate whether the measurement location is prior to or aft er comingling with non-compressor emission

sources. (5) Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting . Centrifugal compressors with wet seal degassing v ents in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting must report the information specified in paragraphs (o)(5)(i) through (i v ) of this section. (i) Number of centrifugal compressors that have wet seal oil degassing vents. (ii) A list of the well ID numbers for the wells at which these compressors are located (for the onshore petroleum and natural gas producti on industry segment only). (ii i ) Annual CO 2 emissions, in metric tons CO 2 , from centrifugal compressors with wet seal oil degassing vents. Deleted: iiPage 154 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (i v ) Annual CH 4 emissions, in metric tons CH 4 , from centrifugal compressors with wet seal oil degassing vents. (p) Reciprocating compressors. You must indicate wh ether your facility has reciprocating compressors. You must report the information specif ied in paragraphs (p)(1) and (2) of this section for all reciprocating compressors at your f acility. For each compressor source or manifolded group of compressor sources that you con duct as found leak measurements as specified in § 98.233(p)(2) or (4), you must report the information specified in paragraph (p)(3) of this section. For each compressor source or mani folded group of compressor sources that you conduct continuous monitoring as specified in § 98. 233(p)(3) or (5), you must report the information specified in paragraph (p)(4) of this s ection. Reciprocating compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting are not required to report information in paragraph s (p)(1) through (4) of this section and instead must report the information specified i n paragraph (p)(5) of this section. (1) Compressor activity data. Report the informatio n specified in paragraphs (p)(1)(i) through (xiv) of this section for each reciprocatin g compressor located at your facility. (i) Unique name or ID for the reciprocating compres sor. (ii) Hours in operating-mode. (iii) Hours in standby-pressurized-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 i n standby-pressurized-mode. (vii) Indicate whether the compressor was measured in not-operating-depressurizedmode. Deleted: iiPage 155 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (viii) Indicate which, if any, compressor sources a re part of a manifolded group of
compressor sources. (ix) Indicate which, if any, compressor sources are routed to a flare. (x) Indicate which, if any, compressor sources have vapor recovery. (xi) Indicate which, if any, compressor source emis sions are captured for fuel use or are routed to a thermal oxidizer. (xii) Indicate whether the compressor has blind fla nges installed and associated dates. (xiii) Power output of the compressor driver (hp). (xiv) Indicate whether the compressor had a schedul ed depressurized shutdown during the reporting year. (2) Compressor source. (i) For each compressor sour ce at each compressor, report the information specified in paragraphs (p)(2)(i)(A) th rough (C) of this section. (A) Reciprocating compressor name or ID. Use the sa me ID as in paragraph (p)(1)(i) of this section. (B) Reciprocating compressor source (isolation valv e, blowdown valve, or rod packing). (C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the sam e leak or vent ID for each compressor source in the manifolded group. If multiple compres sor sources are released through a single vent for which continuous measurements are used, us e the same leak or vent ID for each compressor source released via the measured vent. F or a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source. (ii) For each leak or vent, report the information specified in paragraphs (p)(2)(ii)(A) through (E) of this section.Page 156 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (A) Indicate whether the leak or vent is for a sing le compressor source or manifolded group of compressor sources and whether the emissio ns from the leak or vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery. (B) Indicate whether an as found measurement(s) as identified in § 98.233(p)(2) or (4) was conducted on the leak or vent. (C) Indicate whether continuous measurements as ide ntified in § 98.233(p)(3) or (5) were conducted on the leak or vent. (D) Report emissions as specified in paragraphs (p) (2)(ii)(D)(1) and (2) of this section for the leak or vent. If the leak or vent is routed to flare, combustion, or vapor recovery, you are not required to report emissions under this paragraph. (1) Annual CO 2 emissions, in metric tons CO 2 . (2) Annual CH 4 emissions, in metric tons CH 4 . (E) If the leak or vent is routed to flare, combust ion, or vapor recovery, report the percentage of time that the respective device was o perational when the compressor source emissions were routed to the device. (3) As found measurement sample data. If the measur ement methods specified in § 98.233(p)(2) or (4) are conducted, report the infor mation specified in paragraph (p)(3)(i) of this section. If the calculation specified in § 98.233(p )(6)(ii) is performed, report the information specified in paragraph (p)(3)(ii) of this section. (i) For each as found measurement performed on a le ak or vent, report the information specified in paragraphs (p)(3)(i)(A) through (F) of this section. (A) Name or ID of leak or vent. Use same leak or ve nt ID as in paragraph (p)(2)(i)(C) of this section.Page 157 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (B) Measurement date. (C) Measurement method. If emissions were not detec ted when using a screening method, report the screening method. If emissions w ere detected using a screening method, report only the method subsequently used to measure the volumetric emissions. (D) Measured flow rate, in standard cubic feet per hour. (E) For each compressor attached to the leak or ven t, report the compressor mode during which the measurement was taken. (F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comin gling with non-compressor emission sources. (ii) For each compressor mode-source combination wh ere a reporter emission factor as calculated in Equation W-28 was used to calculate e missions in Equation W-27, report the information specified in paragraphs (p)(3)(ii)(A) t hrough (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 s,m

in Equation W-28). (C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the p receding two reporting years (Count m in Equation W-28). (D) Indicate whether the compressor mode-source com bination reporter emission factor is facility-specific or based on all of the reporte r’s applicable facilities. (4) Continuous measurement data. If the measurement methods specified in § 98.233(p)(3) or (5) are conducted, report the infor mation specified in paragraphs (p)(4)(i)Page 158 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. through (iv) of this section for each continuous me asurement conducted on each leak or vent associated with each compressor source or manifolde d group of compressor sources. (i) Name or ID of leak or vent. Use same leak or ve nt ID as in paragraph (p)(2)(i)(C) of this section. (ii) Measured volume of flow during the reporting y ear, in million standard cubic feet. (iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 9 8.233(p)(3)(ii) and (p)(5)(iii). (iv) If the measurement is for a manifolded group o f compressor sources, indicate whether the measurement location is prior to or aft er comingling with non-compressor emission

sources. (5) Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting . Reciprocating compressors in onshore petroleum an d natural gas production and onshore petroleum and natural gas gathering and boosting must report the information specified in paragraphs (p)(5)(i) throu gh (i v ) of this section. (i) Number of reciprocating compressors. (ii) A list of the well ID numbers for the wells at which these compressors are located (for the onshore petroleum and natural gas producti on industry segment only). (ii i ) Annual CO 2 emissions, in metric tons CO 2 , from reciprocating compressors. (i v ) Annual CH 4 emissions, in metric tons CH 4 , from reciprocating compressors. (q) Equipment leak surveys. If your facility is sub ject to the requirements of § 98.233(q), then you must report the information specified in p aragraphs (q)(1) and (2) of this section. Natural gas distribution facilities with emission s ources listed in § 98.232(i)(1) must also report the information specified in paragraph (q)(3) of th is section. Deleted: ii

Deleted: iiPage 159 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 pa ragraphs (q)(1)(i) and (ii) of this section. (i) Except as specified in paragraph (q)(1)(ii) of this section, the number of complete equipment leak surveys performed during the calenda r year. (ii) Natural gas distribution facilities performing equipment leak surveys across a multiple year leak survey cycle must report the num ber of years in the leak survey cycle. (2) You must indicate whether your facility contain s any of the component 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 facilit y, you must report the information specified in paragraphs (q)(2)(i) through (v) of this section. I f 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 (v) of this section bu t report a zero (“0”) for the information required according to paragraphs (q)(2)(iii), (iv), and (v) of this section. (i) Component type. (ii) Total number of the surveyed component type th at were identified as leaking in the calendar year (“x p ” in Equation W-30 of this subpart for the componen t type). (iii) Average time the surveyed components are assu med to be leaking and operational, in hours (average of “T p,z ” from Equation W-30 of this subpart for the compon ent type). (iv) Annual CO 2 emissions, in metric tons CO 2 , for the component type as calculated using Equation W-30 (for surveyed components only). (v) Annual CH 4 emissions, in metric tons CH 4 , for the component type as calculated using Equation W-30 (for surveyed components only).Page 160 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (3) Natural gas distribution facilities with emissi on sources listed in § 98.232(i)(1) must also report the information specified in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix) of this section. (i) Number of above grade transmission-distribution transfer stations surveyed in the calendar year. (ii) Number of meter/regulator runs at above 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 survey ed in the calendar year were operational, in hours (average of “T w,y ” from Equation W-31 of this subpart, for the curre nt calendar year). (iv) Number of above grade transmission-distributio n transfer stations surveyed in the current leak survey cycle. (v) Number of meter/regulator runs at above grade t ransmission-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). (vi) Average time that meter/regulator runs surveye d 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 transmission

distribution transfer stations in the current leak survey cycle, in standard cubic feet of CO 2 per operational hour of all meter/regulator runs (“EF s,MR,i ” for CO 2 calculated using Equation W-31 of this subpart).Page 161 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (viii) Meter/regulator run CH 4 emission factor based on all surveyed transmission

distribution transfer stations in the current leak survey cycle, in standard cubic feet of CH 4 per operational hour of all meter/regulator runs (“EF s,MR,i ” for CH 4 calculated using Equation W-31 of this subpart). (ix) If your natural gas distribution facility perf orms equipment leak surveys across a multiple year leak survey cycle, you must also repo rt: (A) The total number of meter/regulator runs at abo ve grade transmission-distribution transfer stations at your facility (“Count MR ” in Equation W-32B of this subpart). (B) Average estimated time that each meter/regulato r run at above grade transmissiondistribution transfer stations was operational in t he calendar year, in hours per meter/regulator run (“T w,avg ” in Equation W-32B of this subpart). (C) Annual CO 2 emissions, in metric tons CO 2 , for all above grade transmissiondistribution transfer stations at your facility. (D) Annual CH 4 emissions, in metric tons CH 4 , for all above grade transmissiondistribution transfer stations at your facility. (r) Equipment leaks by population count. If your fa cility is subject to the requirements of § 98.233(r), then you must report the information s pecified in paragraphs (r)(1) through (3) of this section, as applicable. (1) You must indicate whether your facility contain s any of the emission source types required to use Equation W-32A of this subpart. You must report the information specified in paragraphs (r)(1)(i) through (v) of this section se parately for each emission source type required to use Equation W-32A of this subpart that is locat ed at your facility. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boostingPage 162 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. facilities must report the information specified in paragraphs (r)(1)(i) through (v) of this section separately by component type, service type, and geo graphic location (i.e., Eastern U.S. or Western U.S.). (i) Emission source type. Onshore petroleum and nat ural gas production facilities and onshore petroleum and natural gas gathering and boo sting facilities must report the component type, service type and geographic location. For the onshore petroleum and natural gas producti on facilities only, also report a list of well ID numb ers for the associated wells. (ii) Total number of the emission source type at th e facility (“Count e ” in Equation W-32A of this subpart). (iii) Average estimated time that the emission sour ce 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 r eport the information specified in paragraphs (r)(2)(i) through (v) of this section. (i) Number of above grade transmission-distribution transfer stations at the facility. (ii) Number of above grade metering-regulating stat ions that are not transmissiondistribution transfer stations at the facility. (iii) Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution trans fer stations (“Count MR ” in Equation W-32B of this subpart). (iv) Average estimated time that each meter/regulat or run at above grade meteringregulating stations that are not above grade transm ission-distribution transfer stations wasPage 163 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. operational in the calendar year, in hours per mete r/regulator run (“T w,avg ” in Equation W-32B of this subpart). (v) If your facility has above grade metering-regul ating stations that are not above grade transmission-distribution transfer stations and you r facility also has above grade transmissiondistribution transfer stations, you must also repor t: (A) Annual CO 2 emissions, in metric tons CO 2 , from above grade metering regulating stations that are not above grade transmission-dist ribution transfer stations. (B) Annual CH 4 emissions, in metric tons CH 4 , from above grade metering regulating stations that are not above grade transmission-dist ribution transfer stations. (3) Onshore petroleum and natural gas production fa cilities and onshore petroleum and natural gas gathering and boosting facilities must also report the information specified in paragraphs (r)(3)(i) and (ii) of this section. (i) Calculation method used. (ii) Onshore petroleum and natural gas production f acilities and onshore petroleum and natural gas gathering and boosting facilities must report the information specified in paragraphs (r)(3)(ii)(A) and (B) of this section, for each maj or equipment type, production type (i.e., natural gas or crude oil), and geographic location combinat ion 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.Page 164 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (s) Offshore petroleum and natural gas production. You must report the information specified in paragraphs (s)(1) through (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 E OR injection pump blowdowns occurred during the year. If any EOR injection pump blowdown s occurred during the calendar year, then you must report the information specified in paragr aphs (w)(1) through (8) of this section for each EOR injection pump system. (1) Sub-basin ID. (2) EOR injection pump system identifier and a list of the well ID number(s) associated with each EOR injection pump

. (3) Pump capacity, in barrels per day. (4) Total volume of EOR injection pump system equip ment 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 injection gas, in kilograms per cubic foot (“R c ” in Equation W-37 of this subpart).Page 165 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (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 whet her hydrocarbon liquids were produced through EOR operations. If hydrocarbon liq uids were produced through EOR operations, you must report the information specifi ed in paragraphs (x)(1) through ( 5 ) of this section for each sub-basin category with EOR operat ions. (1) Sub-basin ID. (2) A list of the well ID numbers associated with t he EOR operations in each sub-basin. ( 3 ) Total volume of hydrocarbon liquids produced thro ugh EOR operations in the calendar year, in barrels (“V hl ” in Equation W-38 of this subpart). ( 4 ) Average CO 2 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel under standard conditions (“ S hl ” in Equation W-38 of this subpart). ( 5 ) Annual CO 2 emissions, in metric tons CO 2 , from CO 2 retained in hydrocarbon liquids produced through EOR operations downstream of the s torage tank (“Mass CO2 ” in Equation W-38 of this subpart). (y) [Reserved] (z) Combustion equipment at onshore petroleum and n atural gas production facilities , onshore petroleum and natural gas gathering and boo sting facilities, and natural gas distribution facilities. If your facility is required by § 98.23 2(c)(22) , (i)(7) , or (j)(12) to report emissions from combustion equipment, then you must indicate whethe r your facility has any combustion units subject to reporting according to paragraphs (a)(1) (xvii) , (a)(8)(i) , or (a)(9)(xi) of this section. If Deleted: 4

Deleted: 2

Deleted: 3

Deleted: 4

Deleted: or

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This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. your facility contains any combustion units subject to reporting according to paragraphs (a)(1)(xvii) , (a)(8)(i) , or (a)(9)(xi) of this section, then you must report the informat ion specified in paragraphs (z)(1) and (2) of this section, as ap plicable. (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 yo u must report the information specified in paragraphs (z)(1)(i) through (ii i ) of this section for each unit type. (i) The type of combustion unit. (ii) The total number of combustion units. (iii) A list of the well ID numbers associated with the combustion units (for the onshore petroleum and natural gas production industry segme nt only). (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 grea ter than 1 million Btu per hour (or the equivalent of 130 horsepower); or, internal fuel co mbustion units of any heat capacity that are compressor-drivers. If your facility contains: exte rnal fuel combustion units with a rated heat capacity greater than 5 mmBtu/hr; internal fuel com bustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million B tu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of a ny heat capacity that are compressor-drivers, Deleted: or

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This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. then you must report the information specified in p aragraphs (z)(2)(i) through (vi i ) of this section for each combustion unit type and fuel type combina tion. (i) The type of combustion unit. (ii) A list of the well ID numbers associated with the combustion units (for the onshore petroleum and natural gas production industry segme nt only). (ii i ) The type of fuel combusted. (i v ) The quantity of fuel combusted in the calendar ye ar, in thousand standard cubic feet, gallons, or tons. (v) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98.233(z)(1) and (2). (v i ) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98.233(z)(1) and (2). (vi i ) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98.233(z)(1) and (2). (aa) Each facility must report the information spec ified in paragraphs (aa)(1) through ( 11 ) of this section, for each applicable industry segme nt, by using best available data. If a quantity required to be reported is zero, you must report ze ro as the value. (1) For onshore petroleum and natural gas productio n, report the data specified in paragraphs (aa)(1)(i) and (ii) of this section. (i) Report the information specified in paragraphs (aa)(1)(i)(A) through (C) of this section for the basin as a whole. (A) The quantity of gas produced in the calendar ye ar from wells, in thousand standard cubic feet. This includes gas that is routed to a p ipeline, vented or flared, or used in field Deleted: ii

Deleted: i

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This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 ye ar for sales, in thousand standard cubic feet. (C) The quantity of crude oil and condensate produc ed in the calendar year for sales, in barrels. (ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (M) of this section for each unique sub-basin category. (A) State. (B) County. (C) Formation type. (D) The number of producing wells and a list of the well ID numbers at the end of the calendar year (exclude only those wells permanently taken out of production, i.e., plugged and abandoned). (E) The number of producing wells and a list of the well ID numbers acquired during the calendar year. (F) The number of producing wells and a list of the well ID numbers divested during the calendar year. (G) The number of wells and a list of the well ID numbers completed during the calendar
year. (H) The number of wells permanently taken out of pr oduction (i.e., plugged and abandoned) and a list of the well ID numbers during the calendar year. (I) Average mole fraction of CH 4 in produced gas.Page 169 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (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 gra vity of all wells. (M) If an oil sub-basin, report average low pressur e separator pressure, in pounds per square inch gauge. (2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) and (ii) of this section. (i) The total quantity of gas handled at the offsho re platform in the calendar year, in thousand standard cubic feet, including production volumes and volumes transferred via pipeline from another location. (ii) The total quantity of oil and condensate handl ed at the offshore platform in the calendar year, in barrels, including production vol umes and volumes transferred via pipeline from another location. (3) For natural gas processing, report the informat ion specified in paragraphs (aa)(3)(i) through (vii) of this section. (i) The quantity of natural gas received at the gas processing plant in the calendar year, in thousand standard cubic feet. (ii) The quantity of processed (residue) gas leavin g the gas processing plant in the calendar year, in thousand standard cubic feet. (iii) The cumulative quantity of all NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in barrels.Page 170 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iv) The cumulative quantity of all NGLs (bulk and fractionated) leaving the gas processing plant in the calendar year, in barrels. (v) Average mole fraction of CH 4 in natural gas received. (vi) Average mole fraction of CO 2 in natural gas received. (vii) Indicate whether the facility fractionates NG Ls. (4) For natural gas transmission compression, repor t the quantity specified in paragraphs (aa)(4)(i) through (v) of this section. (i) The quantity of gas transported through the com pressor station in the calendar year, in thousand standard cubic feet. (ii) Number of compressors. (iii) Total compressor power rating of all compress ors 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 (iii) of this section. (i) The quantity of gas injected into storage in th e 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 quantity o f LNG imported in the calendar year, in thousand standard cubic feet.Page 171 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 o f LNG exported in the calendar year, in thousand standard cubic feet. (8) For LNG storage, report the quantities specifie d in paragraphs (aa)(8)(i) through (iii) of this section. (i) The quantity of LNG added into storage in the c alendar 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 quanti ties specified in paragraphs (aa)(9)(i) through (vii) of this section. (i) The quantity of natural gas received at all cus tody transfer stations in the calendar year, in thousand standard cubic feet. This value m ay include meter corrections, but only for the calendar year covered by the annual report. (ii) The quantity of natural gas withdrawn from in- system storage in the calendar year, in thousand standard cubic feet. (iii) The quantity of natural gas added to in-syste m storage in the calendar year, in thousand standard cubic feet. (iv) The quantity of natural gas delivered to end u sers, 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 thir d 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 172 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 LD C for operational purposes, in thousand standard cubic feet. (vii) The estimated quantity of gas stolen in the c alendar year, in thousand standard cubic feet. (10) For onshore petroleum and natural gas gatherin g and boosting facilities, report the quantities specified in paragraphs (aa)(10)(i) thro ugh (v) of this section. (i) The quantity of produced gas throughput in the calendar year, in thousand standard cubic feet. (ii) The quantity of produced gas consumed by the f acility in the calendar year, in thousand standard cubic feet. (iii) The quantity of produced condensate throughpu t in the calendar year, in barrels. (iv) The quantity of produced oil throughput in the calendar year, in barrels. (v) The quantity of gas flared, vented and/or unacc ounted for in the calendar year, in thousand standard cubic feet. (11) For onshore natural gas transmission pipeline facilities, report the quantities specified in paragraphs (aa)(11)(i) through (vi) of this section. (i) The quantity of natural gas received at all cus tody transfer stations in the calendar year, in thousand standard cubic feet. This value m ay include meter corrections, but only for the calendar year covered by the annual report. (ii) The quantity of natural gas withdrawn from in- system storage in the calendar year, in thousand standard cubic feet. (iii) The quantity of natural gas added to in-syste m storage in the calendar year, in thousand standard cubic feet.Page 173 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (iv) The quantity of natural gas transferred to thi rd parties such as LDCs or other transmission pipelines, in thousand standard cubic feet. (v) The quantity of natural gas consumed by the tra nsmission pipeline facility for operational purposes, in thousand standard cubic fe et. (vi) The miles of transmission pipeline in the faci lity. (bb) For any missing data procedures used, report t he information in § 98.3(c)(8) except as provided in paragraphs (bb)(1) and (2) of this s ection. (1) For quarterly measurements, report the total nu mber of quarters that a missing data procedure was used for each data element rather tha n the total number of hours. (2) For annual or biannual (once every two years) m easurements, you do not need to report the number of hours that a missing data proc edure was used for each data element. (cc) If you elect to delay reporting the informatio n in paragraph (g)(5)(i), (g)(5)(ii), (h)(1)(iv), (h)(2)(iv), (j)(1)( v ), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii ), (l)(4)(iii), (m)(5), or (m)(6) of this section, you must report the informa tion required in that paragraph no later than the date 2 years following the date specified in § 98.3(b) introductory text. § 98.237 Records that must be retained. Monitoring Plans, as described in § 98.3(g)(5), mus t 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. (b) Results of all emissions detected and measureme nts. (c) Calibration reports for detection and measureme nt instruments used. (d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions. Deleted: iiiPage 174 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. (e) The records required under § 98.3(g)(2)(i) shal l include an explanation of how company records, engineering estimation, or best av ailable information are used to calculate each applicable parameter under this subpart. (f) For each time a missing data procedure was used , keep a record listing the emission source type, a description of the circumstance that resulted in the need to use missing data procedures, the missing data provisions in § 98.235 that apply, the calculation or analysis used to develop the substitute value, and the substitute va lue. § 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 pa rt. Acid gas means hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) contaminants that are separated from sour natural gas by an acid gas removal unit. Acid gas removal unit (AGR) means a process unit th at separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid o r solid absorbents or membrane separators. Acid gas removal vent emissions mean the acid gas s eparated 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 hydrocarb on liquids and occurs either in a discrete gaseous phase at the wellhead or is released from t he liquid hydrocarbon phase by separation. This does not include venting or flaring resulting from activities that are reported elsewhere, including tank venting, well completions, and well workovers.Page 175 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 sin gle well-pad. The association ends where the stream from a single well-pad is combined with stre ams 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 well-p ad are considered a part of the onshore production facility. Basin means geologic provinces as defined by the Am erican Association of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wa llace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991) (incorporated by reference , see § 98.7) and the Alaska Geological Province Boundary Map, Compiled by the American Ass ociation of Petroleum Geologists Committee on Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see § 98.7). Compressor means any machine for raising the pressu re of a natural gas or CO 2 by drawing in low pressure natural gas or CO 2 and discharging significantly higher pressure natu ral gas or CO 2. Compressor mode means the operational and pressuriz ed status of a compressor. For a centrifugal compressor, “mode” refers to either ope rating-mode or not-operating-depressurizedmode. For a reciprocating compressor, “mode” refers to either: operating-mode, standbypressurized-mode, or not-operating-depressurized-mo de. Compressor source means the source of certain venti ng or leaking emissions from a centrifugal or reciprocating compressor. For centri fugal compressors, “source” refers to blowdown valve leakage through the blowdown vent, u nit isolation valve leakage through anPage 176 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. open blowdown vent without blind flanges, and wet s eal oil degassing vents. For reciprocating compressors, “source” refers to blowdown valve leak age through the blowdown vent, unit isolation valve leakage through an open blowdown ve nt without blind flanges, and rod packing emissions. Condensate means hydrocarbon and other liquid, incl uding both water and hydrocarbon liquids, separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at storage conditions. Delineation well means a well drilled in order to d etermine the boundary of a field or producing reservoir. Distribution pipeline means a pipeline that is desi gnated 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/o r approximated physical parameters such as dimensions of containment, actual pressures, actual temperatures, and compositions. Enhanced oil recovery (EOR) means the use of certai n methods such as water flooding or gas injection into existing wells to increase the r ecovery of crude oil from a reservoir. In the context of this subpart, EOR applies to injection o f critical phase or immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil. External combustion means fired combustion in which the flame and products of combustion are separated from contact with the proc ess fluid to which the energy is delivered. Process fluids may be air, hot water, or hydrocarbo ns. External combustion equipment may include fired heaters, industrial boilers, and comm ercial and domestic combustion units.Page 177 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Facility with respect to natural gas distribution f or purposes of reporting under this subpart and for the corresponding subpart A require ments 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 independent m unicipally-owned distribution system. Facility with respect to natural gas distribution f or purposes of reporting under this subpart and for the corresponding subpart A require ments 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 independent m unicipally-owned distribution system. Facility with respect to petroleum and natural gas gathering and boosting for purposes of reporting under this subpart and for the correspond ing subpart A requirements means all gathering pipelines and other equipment located alo ng those pipelines that are under common ownership or common control by a gathering and boos ting system owner or operator and that are located in a single hydrocarbon basin as defined in this section. Where a person owns or operates more than one gathering and boosting system in a ba sin (for example, separate gathering lines that are not connected), then all gathering and boo sting equipment that the person owns or operates in the basin would be considered one facil ity. Any gathering and boosting equipment that is associated with a single gathering and boos ting system, including leased, rented, or contracted activities, is considered to be under co mmon control of the owner or operator of the gathering and boosting system that contains the pip eline. The facility does not include equipment and pipelines that are part of any other industry s egment defined in this subpart.Page 178 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Facility with respect to the onshore natural gas tr ansmission pipeline segment means the total U.S. mileage of natural gas transmission pipe lines, as defined in this section, owned and operated by an onshore natural gas transmission pip eline owner or operator as defined in this section. Facility with respect to onshore petroleum and natu ral gas production for purposes of reporting under this subpart and for the correspond ing 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 EOR operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petr oleum and natural gas production owner or operator and that are located in a single hydrocarb on basin as defined in § 98.238. Where a person or entity owns or operates more than one wel l in a basin, then all onshore petroleum and natural gas production equipment associated with al l wells that the person or entity owns or operates in the basin would be considered one facil ity. Farm Taps are pressure regulation stations that del iver gas directly from transmission pipelines to generally rural customers. In some cas es a nearby LDC may handle the billing of the gas to the customer(s). Field means oil and gas fields identified in the Un ited States as defined by the Energy Information Administration Oil and Gas Field Code M aster List 2008, DOE/EIA 0370(08) (incorporated by reference, see § 98.7). Flare, for the purposes of subpart W, means a combu stion device, whether at ground level or elevated, that uses an open or closed flame to c ombust waste gases without energy recovery. Flare combustion efficiency means the fraction of h ydrocarbon gas, on a volume or mole basis, that is combusted at the flare burner tip.Page 179 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 remo val 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 ar e 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 hydro carbon liquids through passive reduction in pressure or temperature, or portable dewpoint suppr ession skids. Gathering and boosting system means a single networ k of pipelines, compressors and process equipment, including equipment to perform n atural gas compression, dehydration, and acid gas removal, that has one or more connection p oints to gas and oil production and a downstream endpoint, typically a gas processing pla nt, transmission pipeline, LDC pipeline, or other gathering and boosting system. Gathering and boosting system owner or operator mea ns any person that holds a contract in which they agree to transport petroleum or natur al gas from one or more onshore petroleum and natural gas production wells to a natural gas p rocessing facility, another gathering and boosting system, a natural gas transmission pipelin e, or a distribution pipeline, or any person responsible for custody of the gas transported.Page 180 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 planne d deviation from primarily vertical to a primarily horizontal inclination or declination t racking in parallel with and through the target formation. Internal combustion means the combustion of a fuel that occurs with an oxidizer (usually air) in a combustion chamber. In an internal combus tion engine the expansion of the hightemperature and -pressure gases produced by combust ion applies direct force to a component of the engine, such as pistons, turbine blades, or a n ozzle. This force moves the component over a distance, generating useful mechanical energy. Inte rnal combustion equipment may include gasoline and diesel industrial engines, natural gas -fired reciprocating engines, and gas turbines. Liquefied natural gas (LNG) means natural gas (prim arily methane) that has been liquefied by reducing its temperature to -260 degre es Fahrenheit at atmospheric pressure. LNG boil-off gas means natural gas in the gaseous p hase 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 sou rce (as defined in this section) that is manifolded to a common vent that routes gas from multiple compressors. Manifolded group of compressor sources means a coll ection of any combination of manifolded compressor sources (as defined in this s ection) that are manifolded to a common

vent. Meter/regulator run means a series of components us ed in regulating pressure or metering natural gas flow, or both, in the natural gas distr ibution industry segment. At least one meter, at least one regulator, or any combination of both on a single run of piping is considered one meter/regulator run.Page 181 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 me ters 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, metha ne, heavier hydrocarbons and carbon dioxide. Natural gas may be field quality, pipeline quality, or process gas. Offshore means seaward of the terrestrial borders o f 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 th e jurisdiction and control of the United States under the Outer Continental Shelf Lands Act. Onshore natural gas transmission pipeline owner or operator means, for interstate pipelines, the person identified as the transmissio n pipeline owner or operator on the Certificate of Public Convenience and Necessity issued under 15 U.S.C. 717f, or, for intrastate pipelines, the person identified as the owner or operator on the t ransmission pipeline’s Statement of Operating Conditions under section 311 of the Natural Gas Pol icy Act. Onshore petroleum and natural gas production owner or operator means the person or entity who holds the permit to operate petroleum an d natural gas wells on the drilling permit or an operating permit where no drilling permit is iss ued, which operates an onshore petroleum and/or natural gas production facility (as describe d in § 98.230(a)(2)). Where petroleum and natural gas wells operate without a drilling or ope rating permit, the person or entity that pays the State or Federal business income taxes is considere d the owner or operator.Page 182 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Operating pressure means the containment pressure t hat characterizes the normal state of gas or liquid inside a particular process, 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 e qual to 60 psig; greater than 60 psig and less than or equal to 110 psig; greater than 110 psig an d less than or equal to 200 psig; and greater than 200 psig. The pressure in the context of press ure groups is either the well shut-in pressure; well casing pressure; or you may use the casing-to- tubing pressure of one well from the same sub-basin multiplied by the tubing pressure for eac h 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 use d 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/o r gases. Reduced emissions completion means a well completio n following hydraulic fracturing where gas flowback emissions from the gas outlet of the separator that are otherwise vented are captured, cleaned, and routed to the flow line or c ollection system, re-injected into the well or another well, used as an on-site fuel source, or us ed for other useful purpose that a purchased fuel or raw material would serve, with de minimis d irect venting to the atmosphere. Short periods of flaring during a reduced emissions compl etion may occur.Page 183 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Reduced emissions workover means a well workover wi th hydraulic fracturing (i.e., refracturing) where gas flowback emissions from the gas outlet of the separator that are otherwise vented are captured, cleaned, and routed to the flow line or collection system, reinjected 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 de minimis direct venting to the atmosphere. Short periods of flaring during a reduc ed emissions workover may occur. Residue Gas and Residue Gas Compression mean, respe ctively, production lease natural gas from which gas liquid products and, in some cas es, non-hydrocarbon components have been extracted such that it meets the specifications set by a pipeline transmission company, and/or a distribution company; and the compressors operated by the processing facility, whether inside the processing facility boundary fence or outside t he fence-line, that deliver the residue gas from the processing facility to a transmission pipeline. Separator means a vessel in which streams of multip le phases are gravity separated into individual streams of single phase. Sub-basin category, for onshore natural gas product ion, means a subdivision of a basin into the unique combination of wells with the surfa ce 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 gas 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. Permeability for a res ervoir type shall be determined by engineering estimate. Wells that prod uce only from high permeability gas, shale gas, coal seam, or other tight gas reservoir rock a re considered gas wells; gas wells producingPage 184 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. from more than one of these formation types shall b e classified into only one type based on the formation with the most contribution to production as determined by engineering knowledge. All wells that produce hydrocarbon liquids (with or wit hout 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 we lls 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. Transmission-distribution (T-D) transfer station me ans a metering-regulating station where a local distribution company takes part or al l of the natural gas from a transmission pipeline and puts it into a distribution pipeline. Transmission pipeline means a Federal Energy Regula tory Commission rate-regulated Interstate pipeline, a state rate-regulated Intrast ate pipeline, or a pipeline that falls under the “Hinshaw Exemption” as referenced in section 1(c) o f the Natural Gas Act, 15 U.S.C. 717-717 (w)(1994). Tubing diameter groups are defined as follows: Oute r diameter less than or equal to 1 inch; outer diameter greater than 1 inch and less t han 2.375 inch; and outer diameter greater than or equal to 2.375 inch. Tubing systems means piping equal to or less than o ne half inch diameter as per nominal pipe size. Turbine meter means a flow meter in which a gas 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.Page 185 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Vented emissions means intentional or designed rele ases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not including stati onary combustion flue gas), including process designed flow to the atmosphere through seals or ve nt pipes, equipment blowdown for maintenance, and direct venting of gas used to powe r equipment (such as pneumatic devices). Vertical well means a well bore that is primarily v ertical 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, int ercepting the targets either vertically or at an angle. Well identification (ID) number means the unique an d permanent identification number assigned to a petroleum or natural gas well. If the well has been assigned a US Well Number, the well ID number required in this subpart is the US W ell Number. If a US Well Number has not been assigned to the well, the well ID number is th e identifier established by the well’s permitting authority. 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 reg ulatory, commercial, or technical purposes. If well testing is conducted immediately after well co mpletion or workover, then it is considered part of well completion or workover. Wildcat well means a well outside known fields or t he first well drilled in an oil or gas field where no other oil and gas production exists.Page 186 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Table W -1A of Subpart W of Part 98—Default Whole Gas Emiss ion Factors for Onshore Petroleum and Natural Gas Production Facilities and Onshore Petroleum and Natural Gas Gathering and Boosting Facilities Onshore petroleum and natural gas production and Onshore petroleum

and natural gas gathering and boosting Emission factor (scf/hour/component) Eastern U.S. Population Emission Factors—All Components, Gas Ser vice 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 C rude 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 C rude Service 6 Valve 0.0005 Flange 0.0009 Connector (other) 0.0003 Open-ended Line 0.006 Other 5 0.003 Population Emission Factors—Gathering Pipelines Gathering Pipeline 7 2.81 Western U.S. Population Emission Factors—All Components, Gas Ser vice 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 37.3Page 187 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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 and Onshore petroleum

and natural gas gathering and boosting Emission factor (scf/hour/component) Intermittent Bleed Pneumatic Device Vents 2 13.5 Pneumatic Pumps 3 13.3

Population Emission Factors—All Components, Light C rude 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 C rude Service 6 Valve 0.0005 Flange 0.0009 Connector (other) 0.0003 Open-ended Line 0.006 Other 5 0.003 Population Emission Factors—Gathering Pipelines Gathering Pipeline 7 2.81
1 For multi-phase flow that includes gas, use the ga s service emissions factors. 2 Emission Factor is in units of “scf/hour/device.” 3 Emission Factor is in units of “scf/hour/pump.” 4 Hydrocarbon liquids greater than or equal to 20°AP I are considered “light crude.” 5 “Others” category includes instruments, loading ar ms, pressure relief valves, stuffing boxes, compres sor seals, dump lever arms, and vents. 6 Hydrocarbon liquids less than 20°API are considere d “heavy crude.” 7 Emission factor is in units of “scf/hour/mile of p ipeline.”

Table W -1B to Subpart W of Part 98—Default Average Compone nt Counts for Major Onshore Natural Gas Production Equipment and Onshore Petroleum and Natural Gas Gathering and Boosting 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 1Page 188 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Major equipment Valves Connectors Open-ended lines Pressure relief valves 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 Compone nt Counts For Major Crude Oil Production Equipment Major equipment Valves Flanges Connectors Open-ende d 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 0 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—Designation 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 IowaPage 189 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes 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. 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 Oklahoma Vermont Oregon Virginia South Dakota West Virginia Texas Wisconsin Utah Washington Wyoming

Table W -2 of Subpart W of Part 98—Default Total Hydrocarbo n 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-Compressor 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 re gulator valves.Page 190 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Table W -3 of Subpart W of Part 98—Default Total Hydrocarbo n Emission Factors for Onshore Natural Gas Transmission Compression Onshore natural gas transmission compression Emissi on 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-Compressor 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 re gulator valves. 2 Emission Factor is in units of “scf/hour/device.”

Table W -4 of Subpart W of Part 98—Default Total Hydrocarbo n Emission Factors for Underground Natural Gas Storage

Underground natural gas storage Emission factor (sc f/hour/component) Leaker Emission Factors—Storage Station, Gas Servic e Valve 1 14.84 Connector 5.59 Open-Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 Population Emission Factors—Storage Wellheads, Gas Service Connector 0.01 Valve 0.1 Pressure Relief Valve 0.17 Open Ended Line 0.03Page 191 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. Underground natural gas storage Emission factor (sc f/hour/component) Population Emission Factors—Other Components, Gas S ervice 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 re gulator 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 applied for any e quipment type other than connectors, pumps, or valv es. 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 (sc f/hour/component) Leaker Emission Factors—LNG Terminals Components, L NG Service Valve 1.19 Pump Seal 4.00 Connector 0.34 Other 1 1.77 Population Emission Factors—LNG Terminals Compresso r, Gas Service Vapor Recovery Compressor 2 4.17
1 “Other” equipment type should be applied for any e quipment type other than connectors, pumps, or valv es. 2 Emission Factors is in units of “scf/hour/compress or.”Page 192 of 192

This document showing the proposed amendments to su bpart W is provided for informational purposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version. 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 T ransfer 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-Re gulating 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 4 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.”