Page 1 of 227
Subpart W

— Petroleum and Natural Gas Systems This redline strikeout document represents the changes to subparts A and W regulatory text in the final action: Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Final Rule Signed by the EPA Administrator Gina McCarthy on November 13 , 2014

Subpart A : Section 98.6 is amended by revising the defin ition of “Well completions” to read as follows: Well completions means the process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow characteristics , steps whic h may vent produced gas to the atmosphere via an open pit or tank. Well completion also involves connecting the well bore to the reservoir, which may include treating the formation or installing tubing, packer(s), or lifting equipment , steps that do not si gnificantly vent natural gas to the atmosphere. This process may also include high

- rate flowback of injected gas, water, oil, and proppant used to fracture or re - fracture and prop open new fractures in existing lower permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere

. Subpart W

— Petroleum and Natural Gas Systems is amended as follows: § 98.230 Definition of the source category

. (a) This source category consists of the following industry segments: (1) Offshore petroleum and natural gas production

. Offshore petroleum and natural gas production is any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and th at processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore. In addition, offshore production includes secondary platform structures connected to the platform This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 2 of 227 structure via walkways, storage tanks associated with the platform structure and floating production and storage offloading equipment (FPSO). This source category does not include reporting of emissions from offshore drilling and exploration that is not conducted on production platf orms. (2) Onshore petroleum and natural gas production . Onshore petroleum and natural gas production means all equipment on a single well

- pad or associated with a single well

- pad (including but not limited to compressors, generators, dehydrators, storage v essels, engines, boilers, heaters, flare s, separation and processing equipment, and portable non

- self

- propelled equipment , which includes well drilling and completion equipment, workover equipment, gravity separation equipment, auxiliary non

- transportation

- related equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating o f petroleum and/or natural gas (including condensate). This equipment also includes associated storage or measurement vessels and all enh anced oil recovery (EOR) operations using CO 2 or natural gas injection, and , all petroleum and natural gas production equipment located on islands, artificial islands, or structures connected by a causeway to land, an island, or an artificial island. Onsho re petroleum and natural gas production also means all equipment on or associated with a single enhanced oil recovery (EOR) well pad using CO 2 or natural gas injection. (3) Onshore natural gas processing . Natural gas processing means the separation of natural gas liquids (NGLs) or non

- methane gases from produced natural gas, or the separation of NGLs into one or more component mixtures. Separation includes one or more of the following: forced extraction of natural gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or the capture of CO 2 separated from natural gas streams. This segment also includes all

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 3 of 227 residue gas compression equipment owned or operated by the natural gas processing plant. This industry segment includes processing plan ts that fractionate gas liquids, and processing plants that do not fractionate gas liquids but have an annual average thr oughput of 25 MMscf per day or greater. (4) Onshore natural gas transmission compression

. Onshore natural gas transmission compression means any stationary combination of compressors that move natural gas from production fields, natural gas processing plants, or other transmission compressors through transmission pipelines to natural gas distribution pipelines, LNG storage facilities, or into underground storage. In addition, a transmission compressor station includes equipment for liquids separation, and tanks for the storage of water and hydrocarbon liquids. Residue (sales ) gas compression that is part of onshore natural gas processing p lants are included in the onshore natural gas processing segment and are excluded from this segment. (5) Underground natural gas storage

. Underground natural gas storage means subsurface storage, including depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas); natural gas underground storage processes and operations (including compression, dehydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compressio n units located at the facility that inject and recover natural gas int o and from the underground reservoirs. (6) Liquefied natural gas (LNG) storage

. LNG storage means onshore LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 4 of 227

re - liquefy boil

- off

- gas, re - condensers, and vaporization units for re

- gasification of the liquefied natural gas. (7) LNG import and export equipment

. LNG import equipment means all onshore or offshore equipment that receives imp orted LNG via ocean transport, stores LNG, re

- gasifies LNG, and delivers re

- gasified natural gas to a natural gas transmission or distribution system. LNG export equipment means all onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to any location, including locations in the United States. (8) Natural gas distribution

. Natural gas distribution means the distribution pipelines and metering and regulating equipment at metering

- regulating stations that are operated by a Local Distribution Com pany (LDC) within a single state that is regulated as a separate operating
company by a public utility commission or that is operated as an independent municipally

- owned distribution system. This segment also excludes customer meters and regulators, infrastructure, and pipelines (both interstate and intrastate) delivering natural gas di rectly to major industrial

users an d farm taps upstream of the local distribution company inlet. (b) [Reserved] § 98.231 Reporting threshold

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

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 5 of 227 segment only if emission sources specified in paragraph § 98.232(i) emit 25,000 metric tons of
CO 2 equivalent or more per year. (b) For applying the thresho ld defined in § 98.2(a)(2), natural gas processing facilities must also include owned or operated residue gas compression equipment. § 98.232 GHGs to report

. (a) You must report CO 2 , CH 4 , and N 2 O emissions from each industry segment specified in paragraph (b) through (i) of this section, CO 2 , CH 4 , and N 2 O emissions from each flare as specified in paragraph (b) through (i) of this section, and stationary and portable combustion emissions as applicable as specified in paragraph (k) of this section. (b) For of fshore petroleum and natural gas production, report CO 2, CH 4, and N 2 O emissions from equipment leaks, vented emission, and flare emission source types as identified in the data collection and emissions estimation study conducted by BOEMRE in compliance wit h 30 CFR 250.302 through 304. Offshore platforms do not need to report portable emissions. (c) For an onshore petroleum and natural gas production facility, report CO 2, CH 4 , and
N 2 O emissions from only the following source types on a single well

- pad or ass ociated with a single w ell

- pad: (1) Natural gas pneumatic device venting. (2) [Reserved] (3) Natural gas driven pneumatic pump venting. (4) Well venting for liquids unloading. (5) Gas well venting during well completions without hydraulic fracturing. (6) G as well venting during well completions with hydraulic fracturing. (7) Gas well venting during well workovers without hydraulic fracturing.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 6 of 227 (8) Gas well venting during well workovers with hydraulic fracturing. (9) Flare stack emissions. (10) Storage tanks vented emissions from produced hydrocarbons. (11) Reciprocating compressor rod packing venting. (12) Well testing venting and flaring. (13) Associated gas venting and flaring from produced hydrocarbons. (14) Dehydrator vents. (15) [Reserved] (16) EOR injec tion pump blowdown. (17) Acid gas removal vents. (18) EOR hydrocarbon liquids dissolved CO 2 . (19) Centrifugal compressor venting. (20) [Reserved] (21) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other equipment leak sources (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps). (22) You must use the methods in § 98.233(z) and report under this subpart the emissions of CO 2 , CH 4 , and N 2 O from stati onary or portable fuel combustion equipment that cannot move on road ways under its own power and drive train, and that is located at an onshore petroleum and natural gas production facility as defined in § 98.238. Stationary or portable equipment are the
f

ollowing equipment, which are integral to the extraction, processing, or mov ement of oil or natural gas: well drilling and completion equipment, workover equipment, natural gas dehydra tors, natural gas compressors, electrical generators, steam boilers, and process heaters.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 7 of 227 (d) For onshore natural gas processing, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Blowdown vent stacks. (4) Dehydrator vents. ( 5) Acid gas removal vents. (6) Flare stack emissions. (7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. (e) For onshore natural gas transmission compression, report CO 2 , CH 4 , and N 2 O emissio ns from the follo wing sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Transmission storage tanks. (4) Blowdown vent stacks. (5) Natural gas pneumatic device venting. (6) [Reserved] Flare stack emissions. (7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. (f) For underground natural gas storage, report CO 2 , CH 4 , and N 2 O emissions from the followi ng sources: (1) Reciprocating compressor rod packing venting.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 8 of 227 (2) Centrifugal compre ssor venting. (3) Natural gas pneumatic device venting. (4) [Reserved] Flare stack emissions. (5) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. (g) For LNG storage, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Equipment leaks from valves; pump seals; connectors; vapor recovery compressors, and other equipment leak sources. (4) Flare stack emissions. (h) LNG import and export equipment, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Blowdown vent stacks. (4) Equipment leaks from valves, pump seals, con nectors, vapor recovery compressors, and other equipment leak sources. (5) Flare stack emissions. (i) For natural gas distribution, report CO 2 , CH 4 , and N 2 O emissions from the following

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

- distribution transfer stations, including equipment (1) Equipment leaks from connectors, block valves, control

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 9 of 227 valves, pressure relief valves, orifice meters, regulators, and open

- ended lines at above grade transmission

- distribution transfe r stations

. (2) Equipment leaks from vaults at below grade transmission

- distribution transfer stations. (3) Meters, regulators, and associated equipment Equipment leaks at above grade metering

- regulating station stations that are not above grade transmission

- distribution transfer stations

. (4) Equipment leaks from vaults at below grade metering

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

. (j) [Reserved] (k) Report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary fuel combustion unit by following the requirements of subpart C except for facilities under onshore petroleum and natural gas production and natural gas distribution. Onshore petroleum and natural gas production facilities

m ust report stationary and portable combustion emissions as specified in paragraph (c) of this section. Natural gas distribution facilities must report stationary combustion emissions as specified in paragraph (i) of this section. (l) You must report under subpart PP of this part (Suppliers of Carbon Dioxide), CO 2 emissions captured and transferred off site by following the requirements of subpart PP. § 98.233 Calculating GHG emissions

.
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 10 of 227 You must calculate and report the annual GHG emissions as prescribed in this section. For actual conditions For calculations that specify measurements in actual conditions, reporters
may use a flow or volume measurement system that correct s to standard conditions and determine the flow or volume at standard condition s ; otherwise , reporters must use average atmospheric conditions or typical operating conditions as applicable to the respective monitoring methods in this section. (a) Natural gas pneumatic device venting

. Calculate CH 4 and CO 2 volumetric emissions from conti nuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices using Equation W

- 1 of this section.

t i i t t i t T Conv GHG EF Count Mass * * * *

, = 

## ∑

= = 3

1 , * * *
t t i t t i s T GHG EF Count E (Eq. W

- 1)

Where:

Mass t E s ,i = Annual total mass volumetric GHG emissions at standard conditions in metric tons CO 2 e standard cubic feet per year from a natural gas pneumatic device vent vents, of type types “t ”, ” (continuous high bleed, continuous low bleed, intermittent bleed), for GHG i . Count t = Total number of natural gas pneum atic devices of type “t” (continuous high bleed, continuous low bleed, intermittent bleed) as determined in paragraph (a)(1 ), ) or (a)(2 ), and (a)(3 ) of this section. EF t = Population emission factors for natural gas pneumatic device venting vents (in standard cubic feet per hour per device) of each type “t” listed in Tables W

1A, W

- 3, and W

- 4 of this subpart for onshore petroleum and natural gas production, onshore natural gas transmission compression, and underground natural gas storage facilities, re spectively. GHG i = For onshore petroleum and natural gas production facilities, concentration of GHG i , CH 4 , or CO 2 , in natural gas as defined in paragraph (u)(2)(i) of this section and for onshore natural gas transmission compression facilities, and underg round natural gas storage , GHG i equals 0.975 for CH 4 and 1.1 × 10 −2 for CO 2 facilities, concentration of GHG i , CH 4 or CO 2 , in produced natural gas or processed natural gas for each facility as specified in paragraphs (u)(2)(i), (iii), and (iv) of this sect ion

. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 11 of 227

Conv i = Conversion from standard cubic feet to metric tons CO 2 e; 0.0004 79 for CH 4 , and 0.00005262 for CO 2 . T t = Average estimated number of hours in the operating year the devices, of each type “ t , ”, were operational

. using engineering estimates based on best available data. Default is 8760 hours. (1) For all industry segments, determine “Count t ” for Equation W

- 1 of this subpart for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) by counting the devices, except as specified in paragraph (a)(2) of this section. The reported number of devices must represent the total number of devices for the reporting year. (2) For the onshore petroleum and natural gas pro duction 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 device (continuous high bleed, continuous low bleed, and intermittent bleed) using engineering estimates based on best available data. (1) For onshore petroleum and natural gas production, provide the total number of continuous high bleed, continuous low bleed, or intermittent bleed natural gas pneumatic devices of each type as follows: (i) In the first calendar year, for the total number of each type, you may count the total of each type, or count any percentage number of each type plus an engineering estimate based on best available data of the number not counted. (ii) In t he second consecutive year, for the total number of each type, you may count the total of each type, or count any percentage number of each type plus an engineering estimate based on best available data of the number not counted. (iii) In the third consecu tive calendar year, complete the count of all pneumatic devices, including any changes to equipment counted in prior years.
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 12 of 227 (iv) For the calendar year immediately following the third consecutive calendar year, and for calendar years thereafter, facilities must update the total count of pneumatic devices and adjust accordingly to reflect any modifications due to changes in equipment. (2) For onshore natural gas transmission compression and underground natural gas storage, all natural gas pneumatic devices mu st be counted in the first year and updated every calendar year. (3) For all industry segments, determine the type of pneumatic device using engineering estimates based on best available information. (4) Calculate both CH 4 and CO 2 mass emissions from volum etric emissions using calculations in paragraph (v) of this section. (b) [Reserved] (c) Natural gas driven pneumatic pump venting

. (1) Calculate CH 4 and CO 2 volumetric emissions from natural gas driven pneumatic pump venting using Equation W

- 2 of this sect ion. Natural gas driven pneumatic pumps covered in paragraph (e) of this section do not have to report emissions under this paragraph (c ) of this section. ).


### T Conv GHG EF Count Mass i i i 

### * * * * = T GHG EF Count E i i s * * *

, = (Eq. W

- 2)

Where:

Mass i E s,i = Annual total mass volumetric GHG emissions at standard conditions in metric tons CO 2 e standard cubic feet per year from all natural gas driven pneumatic pump venting, for GHG i . Count = Total number of natural gas driven pneumatic pumps. EF = Population emissions factors for natural gas driven pneumatic pumps (in standard cubic feet per hour per pump venting ) listed in Table s Table W

- 1A of this subpart for onshore petroleum and natural gas production. GHG i = Concentration of GHG i , CH 4 , or CO 2 , i n produced natural gas as defined in paragraph (u)(2)(i) of this section. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 13 of 227

Conv i = Conversion from standard cubic feet to metric tons CO 2 e ; 0.0004 79 for CH 4 , and 0.00005262 for CO 2 . T = Average estimated number of hours in the operating year the pumps were operational

. using engineering estimates based on best available data. Default is 8760 hours. ( 2) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. ( d) Acid gas removal (AGR) vents

. For AGR vent vents (including processes such as amine, membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for
CO 2 only (not CH 4 ) vented directly to the atmosphere or emitted through a flare, engine ( e.g. , permeate from a membran e or de

- adsorbed gas from a pressure swing adsorber used as fuel supplement), or sulfur recovery plant , using any of the calculation method ologie s methods described in this paragraph (d ) of this section, ), as applicable. (1) Calculation Method ology Method 1

. If you operate and maintain a continuous emission s monitoring system ( CEMS ) that has both a CO 2 concentration monitor and volumetric flow rate monitor, you must calculate CO 2 emissions under this subpart by following the Tier 4 Calculation Method ology Meth od and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may follow the manufacturer ’ s instructions or industry standard practice. If a CO 2 concentration monitor and volumetric flow rate monitor are not available, you may elect to install a CO 2 concentration monitor and a volumetric flow rate monitor that comply with all of the requirements specified for the Tier 4 Calculation Method ology Method in subpart C of this part (General Stationary Fuel Combustion Sources ). The calculation and reporting of CH 4 and N 2 O emissions is not required as part of the Tier 4 requirements for AGRs AGR units

. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 14 of 227
(2) Calculation Method ology Me thod 2

. If a CEMS is not available but a vent meter is installed, use the CO 2 composition and annual volume of vent gas to calculate emissions using Equation W

- 3 of this section.

2 2 , * CO S CO a 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 the AGR unit in cubic feet per year at actual conditions as determined by flow meter using methods set forth in § 98.234(b). Alternatively, you may follow the manufacturer ’ s instructions or industry standard practice for calibration of the vent meter. Vol CO2 = Volume Annual average volumetric fraction of CO 2 content in vent gas flowing out of the AGR unit as determined in paragraph (d)(6) of this secti on. (3) Calculation Method ology 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 removal unit to calculate emissions for
CO 2 using Equations W

- 4A or W

- 4B of this section. If inlet gas flow rate is known, use Equation
W

- 4A. If outlet gas flow rate is known, use Equation W

- 4B.
     

− − ∗ = O O I in CO a Vol Vol Vol V E 1 2 , (Eq. W

- 4A)

     

− − ∗ = I O I out CO a Vol Vol Vol V E 1 2 , (Eq. W

- 4B)

Where:

E a, CO2 = Annual volumetric CO 2 emissions at actual conditions, in cubic feet per year. V in = Total annual volume of natural gas flow into the AGR unit in cubic feet per year at actual condition conditions as determined using methods specified in paragraph (d)(5) of this section.

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V ou t = Total annual volume of natural gas flow out of the AGR unit in cubic feet per year at actual condition conditions as determined using methods specified in paragraph (d)(5) of this section. Vol I = Volume Annual average volumetric fraction of CO 2 content i n natural gas flowing into the AGR unit as determined in paragraph (d)(7) of this section. Vol o = Volume Annual average volumetric fraction of CO 2 content in natural gas flowing out of the AGR unit as determined in paragraph (d)(8) of this section. (4) Calculation Method ology Method 4

. If CEMS or a vent meter is not installed, you may calculate emissions using any standard simulation software package s package , such as AspenTech HYSYS ® and , or API 4679 AMINECalc, that uses the Peng

- Robinson equation of
stat e , 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 g as feed temperature, pressure, and flow rate. (ii) Acid gas content of feed natural gas. (iii) Acid gas content of outlet natural gas. (iv) Unit operating hours, excluding downtime for maintenance or standby. (v) Exit temperature of natural gas. (vi) Solve nt pressure, temperature, circulation rate, and weight. (5) Record For Calculation Method 3, determine the gas flow rate of the inlet and when using Equation W

- 4A of this section or the gas flow rate of the outlet when using Equation W

4B of this section for the natural gas stream of an AGR unit using a meter according to methods set forth in § 98.234(b). If you do not have a continuous flow meter, either install a continuous flow meter or use an engineering calculation to determine the flow rate. (6) If (6) F or Calculation Method 2, if a continuous gas analyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 16 of 227
gas stream for each quarter that the AGR unit is operating to determine Vol CO 2 in Equation W

- 3 of this section , according to the methods set forth in § 98.234(b). (7) If For Calculation Method 3, if a continuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas
stream for each quarter that the AGR unit is operating to determine Vol I in Equation W

- 4A or
W

- 4B of this section , accordin g to the methods set forth in § 98.234(b). (8) Determine volume For Calculation Method 3, determine annual average volumetric fraction of CO 2 content in natural gas flowing out of the AGR unit using one of the methods specified in paragraph paragraph s (d)(8 ) (i) through (d)(8)(iii ) of this section. (i) If a continuous gas analyzer is installed on the outlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, you may install a continuous gas analyzer

. (ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet gas stream for each quarter that the AGR unit is operating to determine Vol O in Equation W

- 4A or W

- 4B of this section , according to the me thods set forth in § 98.234(b). (iii) Use If a continuous gas analyzer is not available or installed, you may use sales line quality specification for CO 2 in natural gas. (9) Calculate CO 2 annual volumetric CO 2 emissions at standard conditions using calculations in paragraph (t) of this section. (10) Mass CO 2 emissions shall be calculated from volumetric Calculate annual m ass CO 2 emissions using calculations in paragraph (v) of this section.

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(11) Determine if CO 2 emissions from the AGR unit are recover ed and transferred outside the facility. Adjust the emission CO 2 emission s estimated in paragraphs (d)(1) through (d)(10) of this section downward by the magnitude of emission CO 2 emission s recovered and transferred outside the facility. (e) Dehydrator vents

. For dehydrator vents, calculate annual CH 4 , and CO 2 and N 2 O emissions using any of the applicable calculation m ethod ologie s methods described in paragraphs (e)(1) through (e)(4) of this section. If emissions from dehydrator vents are routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (e )(5 ) of this section. If emissions from dehydrator vents are routed to a flare or regenerator 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. (1) Calculation Method ology Method 1

. Calculate annual mass emissions from dehydrator vents with glycol deh ydrators that have an annual average of daily natural gas throughput that is greater than or equal to 0.4 million standard cubic feet per day by using a software program, such as AspenTech HYSYS ® or GRI

- GLYCalc GLYCalc TM , that uses the Peng

- Robinson equation of state to calculate the equilibrium coefficient, speciates CH 4 and CO 2 emissions from dehydrators, and has provisions to include regenerator control devices, a separator flash tank, stripping gas and a gas injection pump or gas assist pump. A minimum of the T he following parameters must be determined by engineering estimate based on best available data and must be used at a minimum to characterize emissions from dehydrators: (i) Feed natural gas flow rate. (ii) Feed n atural gas water content. (iii) Outlet natural gas water content.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 18 of 227 (iv) Absorbent circulation pump type ( e.g. , natural gas pneumatic/air pneumatic/electric). (v) Absorbent circulation rate. (vi) Absorbent type : including ( e.g. , triethylene glycol (TEG), die thylene 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 parameter by selecting using one of the methods described under paragraph in paragraph s (e)(1)(xi ) ( A ) through (e)(1)(xi)(D ) of this section. (A) Use the wet natural gas composition GHG mole fraction as defined in paragraph (u)(2)(i) or (u)(2)(ii) of this section. (B) If wet natural gas composition the GHG mole fraction cannot be determined using paragraph (u)(2)(i) or (u)(2)(ii) of this section, select a representative analysis. (C) You may use an appropriate sta ndard method published by a consensus

- based standards organization if such a method exists or you may use an industry standard practice as specified in § 98.234(b) to sample and analyze wet natural gas composition. (D) If only composition data for dry natu ral gas is available, assume the wet natural gas is saturated. (2) Calculation Method ology Method 2

. Calculate annual CH 4 and CO 2 volumetric emissions from glycol dehydrators with that have an annual average of daily natural gas

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 19 of 227 throughput that is less than 0.4 million standard cubic feet per day using Equation W

- 5 of this section:
1000 * *

, Count EF E i i s = (Eq. W

- 5)

Where:

E s,i = Annual total volumetric GHG emissions (either CO 2 or CH 4 ) at standard conditions in cubic feet. EF i = Population emission factors for glycol dehydrators in thousand standard cubic feet per dehydrator per year. Use 73.4 for CH 4 and 3.21 for CO 2 at 60 °F and 14.7 psia. Count = Total number of glycol dehydrators with that have an annual average of daily natural gas throughput th at is less than 0.4 million standard cubic feet per day. 1000 = Conversion of EF i in thousand standard cubic feet to standard cubic feet. (3) Calculation Method 3. For d ehydrators of any size Dehydrators that use desiccant , you must calculate emissions from the amount of gas vented from the vessel when it is depressurized for the desiccant refilling process using Equation W

- 6 of this section. Desiccant dehydrator emissions covered in this paragraph do not have to be calculated s eparately using the method specified in paragraph (i) of this section for blowdown vent stacks. (3) Determine if dehydrator unit has vapor recovery. Adjust the emissions estimated in paragraphs (e)(1) or (e)(2) of this section downward by the magnitude of e missions captured. (4) Calculate annual emissions from dehydrator vents to flares or regenerator fire

- box/fire tubes as follows: (A) Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(1) and (e)(2) of this section. (B) Use t he calculation methodology of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas vent. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 20 of 227 (5) Dehydrators that use desiccant shall calculate emissions from the amount of gas
vente d from the vessel when it is depressurized for the desiccant refilling process using Equation
W

- 6 of this section. Desiccant dehydrators covered in (e)(5) of this section do not have to report emissions under (i) of this section. 

# ( ) ) 100 * * 4 ( * % * * * *

1 2 2

, P N G P P D H E n

s = 

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

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 21 of 227 recovered using a vapor recovery system as determined by engineering estimate based on best available data

. ( 6 ) Calculate annual emissions from d ehydrator vents to flares or regenerator fire

- box/fire tubes as follows: ( i ) Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(1) through (e)( 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 CO 2 and CH 4 annual volumetric natural
gas emissions from well ve nting for liquids unloading using one of the calculation

m ethod ologie s m ethods described in paragraphs (f)(1), (f)(2 ) ) , or (f)(3) of this section. Calculate annual CH 4 and CO 2 volumetric and mass emissions using the method described in paragraph (f)(4) of this section. (1) Calculation Methodology 1 Method 1

. Calculate emissions from wells with plunger lifts and wells without plunger lifts separately . For at least one well of each unique well tubing diameter group and pressure group combination in each sub

- basin category (see § 98.238 for the definitions of tubing diameter group, pressure group, and sub

- basin category), where gas wells are vented to the atmosphere to expel liquids accumulated in the tubing, install a recording flow
meter shall be install ed 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 liquids unloading using Equation W

- 7 7 A of this section

. For any tubing diameter group and pressure group combination in a sub

- basin where liquids unloading occurs both with and without plunger

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 22 of 227 lifts, Equation W

- 7 A will be used twice, once for wells with plunger li fts and once for wells without plunger lifts

. 

## ∑

= = h

p p n a FR T E 1 , 

## ∑

= = h

p p a T FR E 1 (Eq. W

- 7 7 A )

Where:

E a ,n = Annual natural gas emissions for all wells of the same tubing diameter group and pressure group combination in a sub

- basin at actual conditions in cubic feet , a, in cubic feet. Calculate emission from wells with plunger lifts and wells without plunger lifts separately

. h = Total number of wells of the same tubing diameter group and pressure group combination in a sub

- basin either with or without plunger lifts

. p = Wells 1 through h of the same tubing diameter group and pressure group combination in a sub

- basin. T p = Cumulative amount of time in hours of venting for each well, p, of the same tubing diameter group and pressur e group combination in a sub

- basin during the year. If the available venting data do not contain a record of the date of the venting events and data are not available to provide the venting hours for the specific time period of January 1 to December 31, yo u may calculate an annualized vent time , T p , using Equation W

- 7 B of this section. FR = Average flow rate in cubic feet per hour for all measured wells venting for of the same tubing diameter group and pressure group combination in a sub

basin, over the duration of the liquids unloading, under actual conditions as determined in paragraph (f)(1)(i) of this section.

p p p p D MP HR T × = (Eq. W

- 7B)

Where:

HR p = Cumulative amount of time in hours of venting for each well, p, during the monitoring period. MP p = Time period, in days, of the monitoring period for e ach well, p. A minimum of 300 days in a calendar year are required. The next period of data collection must start immediately following the end of data collection for the previous reporting year

. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 23 of 227

D p = Time period, in days during which the well, p, was in production (365 if the well was in production for the entire year). (i) Determine the well vent average flow rate (“FR” in Equation W

- 7 A of this section) as specified under paragraph in paragraph s (f)(1)(i ) (A) through (f)(1)(i)(C ) of this section for at least one well in a unique well tubing diameter group and pressure group combination in each sub

basin category. Calculate emissions from wells with plunger lifts and wells without plunger lifts separately. (A) The Calculate the average flow rate per hour of venting is calculated for each unique tubing diameter group and pressure group combination in each su b

- basin category by dividing the recorded total annual flow by the recorded time (in hours) for all measured liquid unloading events with venting to the atmosphere. (B) This Apply the average hourly flow rate per hour is applied calculated under paragraph (f

)(1)(i)(A) of this section to all wells in the same pressure group that have the same tubing diameter group, for the number of hours of venting these wells. (C) A Calculate a new average flow rate is calculated every other calendar year for each reporting s ub

- basin category starting with the first calendar year of data collection. For a new producing sub

- basin category, calculate an average flow rate is calculated beginning in the first year of production. (ii) Calculate natural gas volumetric emissions at s tandard conditions using calculations in paragraph (t) of this section. (2) Calculation Method ology Method 2

. Calculate the total emissions for each sub

- basin from well venting to the atmosphere for liquids unloading without plunger lift assist using Equation W

- 8 of this section.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 24 of 227 

# ( ) ( ) ( ) ( ) ∑ ∑

= = −         ×
− × + × × × × × = W

p V

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

, 0

. 1 10 37

. 0 

# ( ) ( ) ( ) ( ) ∑ ∑

= = −       ×
− × + × × × × × = W

p V

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

. 1 10 37

. 0 (Eq. W

- 8)

Where:

E s ,n = Annual natural gas emissions for each sub

- basin at standard conditions, s, in cubic feet / per year. W = Total number of wells with well venting for liquids unloading for each sub

basin. p = Wells 1 through W with well venting for liquids unloading for each sub

basin. V p = Total number of unloading events in the monitoring period per well, p. 0.37×10 − 3 = {3.14 (pi)/4}/{14.7*144} (psia converted to poun ds per square feet). CD p = Casing internal diameter for each well, p, in inches. WD p = Well depth from either the top of the well or the lowest packer to the bottom of the well, for each well, p, in feet. SP p = For each well, p, shut

- in pressure or surface pressure for wells with tubing production , or casing pressure for each well with no packers , in pounds per square inch absolute (psia ). If casing pressure is not available for each well, you may determine the casing pressure by multiplying the tubing pressure of each well with a ratio of casing pressure to tubing pressure from a well in the same sub

- basin for which the casing pressure is k nown. The tubing pressure must be measured during gas flow to a flow

- line. The shut

- in pressure, surface pressure, or casing pressure must be determined just prior to liquids unloading when the well production is impeded by liquids loading or closed to the flow

- line by surface valves. ); or casing

- to

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

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

- basin, in pounds per square inch absolute (psia). V p = Number of unloading events per year per well, p

. SFR p = Average flow

- line rate of gas for well, p, at standard conditions in cubic feet per hour. Use Equation W

- 33 of this section to calculate the average flow

line rate at standard conditions. HR p,q = Hours that each well, p, was left open to the atmosphere during each unloading event, q. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 25 of 227

1.0 = Hours for average well to blowdown casing volume at shut

- in pressure. q = Unloading event. Z p,q = If HR p,q is less than 1.0 then Z p,q is equal to 0. If HR p,q is greater than or equal to 1.0 then Z p,q is equal to 1. (3) Calculation Method ology Method 3

. Calculate the total emissions for each sub

- basin from well venting to the atmosphere for liquids unloading with plunger lift assist using Equation
W

- 9 of this se ction. 

# ( ) ( ) ( ) ( ) ∑ ∑

= = −       ×
− × + × × × × × = W

p V

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

, 5

. 0 10 37

. 0 

# ( ) ( ) ( ) ( ) ∑ ∑

= = −       ×
− × + × × × × × = W

p V

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

. 0 10 37

. 0 (Eq. W

- 9)

Where:

E s ,n = Annual natural gas emissions for each sub

- basin at standard conditions, s, in cubic feet / per year. W = Total number of wells with plunger lift assist and well venting for liquids unloading for each sub

- basin. p = Wells 1 through W with well venting for liquids unloading for each sub

basin. V p = Total number of unloading events in the monitoring period for each well, p. 0.37×10 − 3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). TD p = Tubing internal diameter for each well, p, in inches. WD p = Tubing depth to plunger bumper for each well, p, in feet. SP p = Flow

- line pressure for each well, p, in pounds per square inch absolute (psia), using engineering es timate based on best available data. V p = Number of unloading events per year for each well, p. SFR p = Average flow

- line rate of gas for well, p, at standard conditions in cubic feet per hour. Use Equation W

- 33 of this section to calculate the average flow

line rate at standard conditions. HR p,q = Hours that each well, p, was left open to the atmosphere during each unloading event, q. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 26 of 227

0.5 = Hours for average well to blowdown tubing volume at flow

- line pressure. q = Unloading event. Z p,q = If HR p,q is less t han 0.5 then Z p,q is equal to 0. If HR p,q is greater than or equal to 0.5 then Z p,q is equal to 1. (i)

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

. Calculate annual volumetric natural gas emissions from gas well venti ng 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 when the flowback rate is measured from a specified number of example completions or workovers and Equation W

- 10B applies when the flowback vent or flare volume is measured for each completion or workover. Completion and workover activities are separated into two periods, an initial period when flowback is routed to open pits or tanks and a subsequ ent period when gas content is sufficient to route the flowback to a separator or when the gas content is sufficient to allow measurement by the devices specified in paragraph (g)(1) of this section, regardless of whether a separator is actually utilized. If you elect to use Equation W

- 10A of this section, you must follow the procedures specified in paragraph (g)(1) of this section. Emissions must be calculated separately for completions and workovers, for each sub

- basin, and for each well type combination 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 gas well venting during completions and workovers with hydraulic fracturing are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (g)(4) of this section. Calculate CH 4 , CO 2 and N 2 O
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 27 of 227 annual emissions from gas well venting during completions involving hydraulic fracturing in wells and well workovers using Equation W

- 10A or Equation W

- 10B of this section. Equation
W

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

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

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

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

- 10B if the flow vo lume for backflow during well completions and workovers from hydraulic fracturing is known for all wells in a sub

basin and well type (horizontal or vertical) combination. Both CH 4 and CO 2 volumetric and mass emissions shall be calculated from volumetric t otal gas emissions using calculations in paragraphs (u) and (v) of this section. 

# [ ] ∑

= − − × × = W

p p s p s p s s p n s SG EnF PR FRM T E 1 , , , , 

# [ ] [ ] ∑

= × ÷ × +

− × × = 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 p s p s n s EnF FV E 1 , , , 

# [ ] [ ] ∑

= ÷ × +

− = W

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

- 10B)

Where:

E s,n = Annual volumetric total natural gas emissions in standard cubic feet at standard conditions from gas well venting during completions or workovers following hydraulic fracturing for each sub

- basin and well type (horizontal vs. vertical) combination. W = Total number of wells completed or worked over using hydraulic fracturing in a sub

- basin and well type (horizontal vs. vertical) combination. T p ,s = Cumulative amount of time of backflow flowback , after sufficient quantities of gas are present to enable separation, where gas vent ed or flare d for the completion or workover, in hours, for each well, p, in a sub

- basin and well This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 28 of 227
type (horizontal vs. vertical) combination during the reporting year. This may include non

- contiguous periods of vent ing or flar ing

. T p,i = Cumulative amount of time of f lowback to open tanks/pits, from when gas is first detected until sufficient quantities of gas are present to enable separation, for the completion or workover, in hours, for each well, p, in a sub

- basin and well type combination during the reporting year. This may include non

- contiguous periods of routing to open tanks/pits. FRM s = Ratio of average flowback , during the period when sufficient quantities of gas are present to enable separation, of well completions and workovers from hydraulic fracturing to 30

- day production rate from Equation W

- 12. for the sub

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

- day average production flow rate in standard cubic feet per hour of each well p, as required in paragraph (g)(1) of this section. FRM i = Ratio of initial flowback rate during well completions and workovers from hydraulic fracturing to 30

- day production rate for the sub

- basin and well type combination, calculated using procedures specified in paragraph (g)(1) (iv) of this section, expressed in standard cubic feet per hour, for the period of flow to open tanks/pits. PR s,p = Average production flow rate during the first 30 days of product ion after completions of newly drilled gas wells or gas well workovers using hydraulic fracturing in standard cubic feet per hour of each well p , that was measured in the sub

- basin and well type combination

. EnF s,p = Volume of CO 2 or N 2 injected gas in cub ic feet at standard conditions that was injected into the reservoir during an energized fracture job for each well , p . , as determined by using an appropriate meter according to methods described in § 98 .234(b), or by using receipts of gas purchases that ar e used for the energized fracture job. Convert to standard conditions using paragraph (t) of this section. If the fracture process did not inject gas into the reservoir , then EnF s,p is 0. If or if the injected gas is CO 2 then EnF s,p is 0. SG s,p = Volume of natural gas in cubic feet at standard conditions that was recovered into a flow

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

- up. If no gas was recovered, SG s,p is 0. FV s,p = Flow volume vented or flared of each well ( , p ) , in standard cubic feet measured using a recording flow meter (digital or analog) on the vent line to measure flowback during the separation period of the completion or workover according to metho ds set forth in § 98.234(b). FR p ,i = Flow rate vented or flared of each well, p, in standard cubic feet per hour measured using a recording flow meter (digital or analog) on the vent line to This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 29 of 227

measure the flowback , at the beginning of the period 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 section, you must use Calculation Method 1 as specifie d in paragraph (g)(1)(i) of this section, or Calculation Method 2 as specified in paragraph (g)(1)(ii) of this section, to determine the value of FRM s and FRM i . These values must be based on the flow rate for flowback, once sufficient gas is present to ena ble separation. The number of measurements or calculations required to estimate FRM s and FRM i must be determined individually for completions and workovers per sub

- basin and well type combination as follows: complete measurements or calculations for a t lea st one completion or workover for less than or equal to 25 completions or workovers for each well type combination within a sub

basin; complete measurements or calculations for at least two completions or workovers for 26 to 50 completions or workovers for each sub

- basin and well type combination; complete measurements or calculations for at least three completions or workovers for 51 to 100 completions or workovers for each sub

- basin and well type combination; complete measurements or calculations for at l east four completions or workovers for 101 to 250 completions or workovers for each sub

- basin and well type combination; and complete measurements or calculations for at least five completions or workovers for greater than 250 completions or workovers for each sub

- basin and well type combination. The average flow rate for flowback during well completions and workovers from hydraulic fracturing shall be determined using measurement(s) for Calculation Methodology 1 or calculation(s) for Calculation Methodology 2 described in this paragraph (g)(1) of this section. If Equation W

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

- basin and well type (horizontal or vertical) as follows: at least one measurement or calculation for le ss than or

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 30 of 227 equal to 25 completions or workovers; at least two measurements or calculations for 26 to 50 completions or workovers; at least three measurements or calculations for 51 to 100 completions or workovers; at least four measurements or calculations for 101 to 250 completions or workovers; and at least five measurements or calculations for greater than 250 completions or workovers. (i) Calculation Method ology Method 1

. You must use Equation W

- 12A as specified in paragraph (g)(1)(iii) of this section to determine the value of FRM s . You must use Equation W

12B as specified in paragraph (g)(1)(iv) of this section to determine the value of FRM i . The procedures specified in paragraphs (g)(1)(v) and (g)(1)(vi) also apply. When making flowback measurements f or use in Equations W

- 12A and W

- 12B of this section, you must use a recording flow meter (digital or analog) installed on the vent line, ahead of a flare or vent, to measure the flowback rates in units of standard cubic feet per hour according to methods s et forth in § 98.2 34(b). When using Equation W

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

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

- basin categ ory and well type (horizontal or vertical) combination, a recording flow meter (digital or analog) shall be installed on the vent line, ahead of a flare or vent if used, to measure the backflow rate according to methods set forth in §98.234(b). (ii) Calcul ation Methodology Method 2

. You must use Equation W

- 12A as specified in paragraph (g)(1)(iii) of this section to determine the value of FRM s . You must use Equation W

12B as specified in paragraph (g)(1)(iv) of this section to determine the value of FRM i . Th e procedures specified in paragraphs (g)(1)(v) and (g)(1)(vi) also apply. When calculating the flowback rates for use in Equations W

- 12A and W

- 12B of this section based on well parameters,

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 31 of 227 you must record the well flowing pressure immediately upstream (and immediately downstream in subsonic flow) of a well choke according to methods set forth in § 98.2 34(b) to calculate the well flowback . The upstream pressure must be surface pressure and reservoir pressure cannot be assumed. The downstream pressure must be measured after the choke and atmospheric pressure cannot be assumed. Calculate flowback rate using Equation W

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

- 11B of this section for sonic flow. You must use best engineering estimates based on best available data along with Equation W

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

- 11C of this section is greater than or equal to 2, then flow is sonic; otherwise, flow is subsonic. Convert calculated FR a values from actual conditions upstream of the restriction orifice to standard conditions (FR s,p and
FR i,p ) for use in Equations W

- 12A and W

- 12B of this section using Equation W

- 33 in paragraph (t) of this section. When using Equation W

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

- basin category and for each calculated well horizontal workover and for each calculated vertical well workover in each gas producing sub

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

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

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

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

- 11C is greater than or equal to 2, then flow is sonic; otherwise, flow is

s ubsonic:

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 32 of 227

               

−         ∗ = 758

. 1

1 2 515

. 1

1 2 5 * * 3430 * * 10 27

. 1 P P P P T A FR u a (Eq. W

- 11A)

Where:

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

u a T A FR * 08

. 187 * * 10 27

. 1 5 ∗ = (Eq. W

- 11B)

Where:

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

2 1 P P R = (Eq. W

- 11C)
Where:

R = Pressure ratio

. P 1 = Pressure immediately upstream of the restriction orifice in pounds per square inch absolute. choke (psia).
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 33 of 227

P 2 = Pressure immediately downstream of the restriction orifice in pounds per square inch absolute. choke (psia). (iii) For Equation W

- 10A , the ratio of this section, calculate FRM s using Equation W

12 A of this section.



# ∑ ∑

= = = N

p p s N

p p s

s PR FR FRM

1 , 1 , (Eq. W

- 12 A )

Where:

FRM s = Ratio of average flowback rate , during the period of time when sufficient quantities of gas are present to enable separation, of well completions and workovers from hydraulic fracturing to 30

- day production rate for each sub

basin and well type combination

. FR s,p = Measured average flowback rate from Calculation Method ology Method 1 described in paragraph (g)(1)(i) of this section or calculated flow average flowback rate from Calculation Method ology Method 2 described in paragraph (g)(1)(ii) of this section , during the separation period in standard cubic feet per hour for well(s) p f or each sub

- basin and well type (horizontal or vertical) combination. Measured Convert m easured and calculated FR a values shall be converted from actual conditions upstream of the restriction orifice (FR a ) to standard conditions (FR s,p ) for each well p usin g Equation W

33 in paragraph (t) of this section. You may not use flow volume as used in Equation W

- 10B converted to a flow rate for this parameter. PR s,p = First 30

- day Average production flow rate during the first 30 days of production after completions of newly drilled gas wells or gas well workovers using hydraulic fracturing, in standard cubic feet per hour for each well , p , that was measured in the sub

- basin and well type combination. N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub

- basin and well type combination. (iv) For Equation W

- 10A of this section, calculate FRM i using Equation W

- 12B of this section.

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, 1

, 1 N i p p i N
s p p FR FRM PR =

= = 

# ∑ ∑ (Eq. W

- 12B)

Where:

FRM i = Ratio of flowback gas rate while flowing to open tanks/pits during well completions and workovers from hydraulic fracturing to 30

- day production rate. FR i,p = Initial measured gas flowback rate from Calculation Method 1 described in pa ragraph (g)(1)(i) of this section or initial calculated flow rate from Calculation Method 2 described in paragraph (g)(1)(ii) of this section in standard cubic feet per hour for well(s), p, for each sub

- basin and well type combination. Measured and calcula ted FR i,p values must be based on flow conditions at the beginning of the separation period and must be expressed at standard conditions. PR s,p = Average production flow rate during the first 30

- days of production after completions of newly drilled gas wel ls or gas well workove rs using hydraulic fracturing, in standard cubic feet per hour of each well, p, that was measured in the sub

- basin and well type combination. N = Number of measured or calculated well completions or workovers using hydraulic fracturin g in a sub

- basin and well type combination. ( iv v ) For Equation W

- 10A of this section , the ratio of backflow flowback rate during well completions and workovers from hydraulic fracturing to 30

- day production rate for horizontal and vertical wells are applied to all horizontal and vertical well completions in the gas producing sub

- basin and well type combination and to all horizontal and vertical well workovers,

r espectively, in the gas producing sub

- basin and well type combination for the total number of hours of backflow flowback and for the first 30 day average production rate for each of these wells. ( v vi ) For Equation W

- 10A, 12 A and W

- 12 B of this section, calcul ate new flow flowback rates for horizontal and vertical gas well completions and horizontal and vertical gas well

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workovers in each sub

- basin category shall be calculated once every two years starting in the first calendar year of data collection. (2) The v olume of CO 2 or N 2 injected into the well reservoir during energized hydraulic fractures will be measured using an appropriate meter as described in 98.234(b) or using receipts of gas purchases that are used for the energized fracture job. (i) Calculate ga s volume at standard conditions using calculations in paragraph (t) of this section. (2) For paragraph s (g) introductory text and (g)(1) of this section, measurements and calculations are completed separately for workovers and completions per sub

- basin and well type combination. A well type combination is a unique combination of the parameters listed in paragraphs (g)(2)(i) through (g)(2)(iii) of this section. (i) Vertical or h orizontal (directional drilling). (ii) [Reserv ed] With flaring or without flaring. (iii) Reduced emission completion/workover or not reduced emission completion/workover. (3) Determine if the backflow gas from the well completion or workover from hydraulic fracturing is recovered with purpose designed equipment that separates natural gas from the backflow, and sends this natural gas to a flow

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

- 10A of this section, to adjust the emissions estimated in paragraphs (g)(1) through (g)(4) of this section by the magnitude of emissions captured using purpose designed equipment that separates saleable gas from the flowback as determined by engineering estimate based on best available data.

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(iii) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section. ( 4 3 ) Both Calculate b oth CH 4 and CO 2 volumetric and mass emissions shall be calculated from total natural gas volumetric total emissions using calculations in paragraphs (u) and (v) of this section. ( 5 4 ) Calculate annual emissions from gas well venting during well completions and workovers from hydraulic fracturing to flares as follows: where all or a portion of the gas is flared as specified in paragraphs (g)(4)(i) and (g)(4)(ii) of thi s section. (i) Use the volumetric total gas well venting volume natural gas emissions vented to the atmosphere during well completions and workovers as determined in paragraph (g) of this section

. to calculate volumetric and mass emissions using paragraphs (u) and (v) of this section. (ii) Use the calculation method ology method of flare stacks in paragraph (n) of this section to determine adjust emissions for the portion of gas well venting flared during well completions and workovers using hydraulic fracturi ng emissions from the flare

. . This adjustment to emissions from completions using flaring , versus completions without flaring , accounts for the conversion of CH 4 to CO 2 in the flare and for the formation on N 2 O during flaring

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

. Calculate CH 4 , CO 2 and N 2 O annual volumetric natural gas emissions from each gas well venting during workovers without hydraulic fracturing using Equation W

- 13 A of this section

. Calculate annual volumetric natural gas emissions from each gas well venting during well completions and workovers not involving hydraulic fracturing using Equation W

- 13 of this section : without hydraulic fracturing using Equation W

- 13B of this section. You must convert annual volumetric natural gas emissions to CH 4 and CO 2 volumetric and mass emissions as

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 37 of 227 specified in paragraph (h)(1) of this section. If emissions from gas well venting during completions and workovers without hydraulic fracturing are routed to a flare, you must calculate
CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (h)(2) of this section. 

# ∑

= 

### + = f

p p p wo wo n s 

### T V EF N E 1 , 

### * * wo wo wo s EF N E *

, = (Eq. W

- 13 13A )

p f

p p p s T V E * 1 , 

## ∑

= = (Eq. W

- 13B )

Where:

E s, n wo = Annual volumetric natural gas emissions in standard cubic feet from gas well venting during well completions and workovers without hydraulic fracturing. N wo = Number of workovers per sub

- basin category that flare gas or vent gas to the atmosphere and do not involve hydraulic fracturing in the reporting year. EF wo = Emission F actor factor for non

- hydraulic fracture well workover venting in standard cubic feet per workover. EF wo = 3114 Use 3 , 114 standard cubic feet natural gas per well workover without hydrau lic fracturing. E s,p = Annual volumetric natural gas emissions in standard cubic feet from gas well venting during well completions without hydraulic fracturing. p = Well completions 1 through f in a sub

- basin. f = Total number of well completions without hydraulic fracturing in a sub

- basin category. V p = Average daily gas production rate in standard cubic feet per hour for each well , p, undergoing completion without hydraulic fracturing , p . This is the total annual gas production volume divided by total nu mber 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 e nd 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 fract uring, p, was venting in hours during the year.

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(1) Volumetric emissions for Calculate both CH 4 and CO 2 shall be calculated volumetric emissions from volumetric natural gas volumetric emissions using calculations in paragraph (u) of this section. Mass emissions for Calculate both CH 4 and CO 2 shall be calculated mass emissions from volumetric natural gas emissions vented to atmosphere using calculations in paragraph s paragraph (v) of this section. (2) Calculate annual emissions of CH 4 , CO 2 , and N 2 O f rom gas well venting to flares during well completions and workovers not involving hydraulic fracturing to flares as follows: as specified in paragraphs (h)(2)(i) and (h)(2)(ii) of this section. (i) Use the gas well venting volume and gas composition during well completions and workovers that are flared as determined using the methods specified in paragraph s (h ) and (h)(1 ) of this section. (ii) Use the calculation method ology method of flare stacks in paragraph (n) of this section to determine emissions from the flare for gas well venting to a flare during well completions and workovers emissions without hydraulic fracturing from the flare

. (i) Blowdown vent stacks

. Calculate CO 2 and CH 4 blowdown vent stack emissions from depressurizing the depr essuriz ation of equipment (s) to reduce system pressure for planned or emergency shutdowns resulting from human intervention or to take equipment out of service for maintenance (excluding depressurizing as specified in either paragraph (i)(2) or (i)(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 other blowdown vent stacks a t your facility. Equipment with a unique physical volume of less than 50 cubic feet as determined in paragraph (i)(1) of this section are not subject to the requirements in paragraphs (i)(2) through (i)(4) of this section. The requirements in this paragrap h (i) do not apply to

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 39 of 227 blowdown vent stack emissions from depressurizing to a flare, over

- pressure relief, operating pressure control venting and , blowdown of non

- GHG gases ; , and desiccant dehydrator blowdown venting before reloading is covered in paragraph (e)(5) of this section) as follows:

. (1) Calculate the Method for calculating unique physical volumes . You must calculate each unique physical volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, discharge bottles, and vessels) between isolation valves determined , in cubic feet, by using engineering estimates based on best available data. (2) If the unique physical volume between isolation valves is greater than or equal to 50 cubic feet, retain logs of the number of blowdowns for each unique physical volume (including but not limited to compressors, vessels, pipelines, headers, fractionators, and tanks). Unique physical volumes smaller than 50 cubic feet are exempt from reporting under paragraph (i) of this section. (3 ) (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 calculated 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 ap plicable, paragraph (i)(2)(iii) of this section for each equipment or event type. Equipment or event types must be grouped into the following seven categories: facility piping ( i.e. , piping within the facility boundary other than physical volumes associated with distribution pipelines ) , pipeline venting ( i.e. , physical volumes associated with distribution pipelines vented within the facility boundary) , compressors, scrubbers/strainers, pig launchers and receivers,
emerg ency shutdowns ( this category includ es emergency shutdown blowdown emissions regardless of equipment type ) , and all other equipment with a physical volume greater than or

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- 14A or W

- 14B of this section. 

## ( ) ( )        

−        
+ +
= C V P T P T V N E

s a a s n s 

### * 67

. 459 67

. 459 *

, 

## ( ) ( ) , 459.67 * * 459.67 s a s n a sa T P E N V V C T PZ     +
= −     +     (Eq. W

- 14A )

Where:

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

. C = Purge factor that is 1 if the unique physical volume is not purged , or zero 0 if the unique physical volume is purged using non

- GHG gases. T s = Temperature at standard conditions (60 °F). T a = Temperature at actual conditions in the unique physical volume (°F). P s = Absolute pressure at standard conditions (14.7 psia). P a = Absolute pressure at actual conditions in the unique physical volume (psia). Z a = Compressibility factor at actual conditions for natural gas. You may use either a default compressibility factor of 1, or a site

- specific compressibility factor based on actual temperature and pressure conditions. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 41 of 227 

## ( ) 

# ( ) ( ) ∑

= 

###                
+ − +
= N

p s p a p e a p b a s n s 

### P T P P T V E 1 , , , , ,

, 

### 67

. 459 67

. 459


## ( ) 

# ( ) ( ) ,, ,,

, 1
, 

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

### TP P E V T PZ
= 

###     + −     = +     

# ∑ (Eq. W

- 14B )

Where:

E s,n = Annual natural gas venting emissions at standard conditions from blowdowns each unique physical volume that is blown down, in cubic feet. p = Individual occurrence of blowdown for the same unique physical volume. N = Number of occurrences of blowdowns for each unique physical volume in the calendar year. V p = Total Unique physical volume (including pipelines, compressors and vessels) between isolation valves , in cubic feet , for each blowdown “p.” T s = Temperature at standard conditions (60 °F). T a,p = Temperature at actual conditions in the unique physical volume ( ° (° F) for each blowdown “p”. P s = Absolute pressure at standard conditions (14.7 psia). P a,b,p = Absolute pressure at actual conditions in t he unique physical volume (psia) at the beginning of the blowdown “p”. P a,e,p = Absolute pressure at actual conditions in the unique physical volume (psia) at the end of the blowdown “p”; 0 if blowdown volume is purged using non

GHG gases. Z a = Compressibi lity 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 conditions. (ii) Except as allowed in paragraph (i)(2)(iii) of this section, c alculate annual CH 4 and
CO 2 volumetric and mass emissions from each unique physical volume that is blown down by using the annual natural gas emission value as calculated in either Equation W

- 14 A or Equation
W

- 14 B of paragraph (i)(2)( i ) of t his section and the calculation method specified in paragraph (i)( 4) of this section. Calculate the total annual CH 4 and CO 2 emissions for each equipment or This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 42 of 227

event type by summing the annual CH 4 and CO 2 mass emissions for all unique physical volumes associa ted with the equipment or event type

. (iii) For onshore natural gas transmission compression facilities and LNG import and export equipment , as an alternative to using the procedures in paragraph (i)(2)( ii ) of this section , you may elect to sum the annual natural gas emissions as calculated using either Equation W

14A or Equation W

- 14B of paragraph (i)(2)(i) of this section for all unique physical volumes associated with the equipment type or event type . Calculate the total annual CH 4 and CO 2 volumetric and mass emissions for each equipment type or event type using th e sum s of the total annual natural gas emissions for each equipment type and the calculation method specified in paragraph (i)(4) of this section. (3) Method for determining emissions from blowdown vent stacks using a flow meter . In lieu of determining emissions from blowdown vent stacks as specified in paragraph (i)(2) of this section, you may use a flow meter and measure blowdown vent stack emissions f or 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 method, you must measure the natural gas emissions from the blowdown(s) through the monitored st ack(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 meter s according to paragraph (i)(4) of this section. (4) Method for converting from natural gas emissions to GHG volumetric and mass emissions

. Calculate both CH 4 and CO 2 volumetric and mass emissions using calculations the methods specified in paragraph paragraphs (u) and (v) of this section. (j) Onshore production storage tanks

. Calculate CH 4 , CO 2 , and N 2 O (when flared) emissions from atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 43 of 227 liquids from onshore petroleum and natural gas production facilities (including stationary liquid storage not owned or operated by the reporter), ca lculate annual CH 4 and CO 2 e missions using any of the calculation methodologies described in this paragraph (j). as specified in this paragraph (j). For wells flowing to gas - liquid separators with annual average daily throughput of oil greater than or equal to 10 barrels per day, calculate annual CH 4 and CO 2 using Calculation Method 1 or
2 as specified in paragraphs (j)(1) and (j)(2) of this section . For wells flowing directly to atmospheric storage tanks without passing 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 paragraph (j)(2) of this section . For wells flowing to gas

- liquid separators or directly to atmospheric storage tanks with throughput less than 10 barrels per day, use Calculation Method 3 as specified in paragraph (j)(3) of this section

. If you use Calculation Meth od 1 or Calculation Method 2, y ou must also calculate emissions that may have occurred due to dump valves not closing properly using the method specified in paragraph (j)(6) of this section. If emissions from atmospheric pressure fixed roof storage tanks a re routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (j)(4) of this section. If emissions from atmospheric pressure fixed roof storage tanks are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual e missions as specified in paragraph ( j )( 5 ) of this section. (1) Calculation Methodology 1

. For separators with annual average daily throughput of oil greater than or equal to 10 barrels per day. (1) Calculation Method 1

. C alculate annual CH 4 and CO 2 emissions from onshore production storage tanks using operating conditions in the last wellhead gas

- liquid separator before liquid transfer to storage tanks. Calculate flashing emissions with a software program, such as AspenTech HYSYS ® or API 4697 E&P Tan k, that uses the

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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 tank. A minimum of the T he following parameters must be determined for typical operating conditions over the year by engineering estimate and process knowledge based on best available data , and must be used at a minimum to characterize emissions from liquid transferred to tanks

. : (i) Separator temperature. (ii) Separator pressure. (iii) Sales oil or stabilized oil API gravity. (iv) Sales oil or stabilized oil production rate. (v) Ambient air temperature. (vi) Ambient air pressure. (vii) Separator oil composition and Reid vapor pressure. If this data is not avail able, determine these parameters by s elect ing using one of the methods described under paragraph in paragraph s (j)(1 ) ( )( vii ) (A) through (j)(1)(vii)(C ) of this section. (A) If separator oil composition and Reid vapor pressure default data are provided with
t he software program, select the default values that most closely match your separator pressure first, and API gravity secondarily. (B) If separator oil composition and Reid vapor pressure data are available through your previous analysis, select the latest available analysis that is representative of produced crude oil or condensate from the sub

- basin category. (C) Analyze a representative sample of separator oil in each sub

- basin category for oil composition and Reid vapor pressure using an appropriate sta ndard method published by a

consensus - based standards organization.

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(2) Calculation Method ology Method 2

. Calculate annual CH 4 and CO 2 emissions from onshore production storage tanks using the methods in paragraph (j)(2)(i) of this section for wellhead wells flowing to gas - liquid separators with annual average daily throughput of oil greater than or equal to 10 barrels per day by assuming . Calculate annual CH 4 and CO 2 emissions using the methods in paragraph (j)(2)(ii) of this section for wells with annual ave rage daily oil production greater than or equal to 10 barrels per day that flow directly to atmospheric storage tanks. (i ) Flow to storage tank after passing through a separator

. A ssume 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 published by a consensus

- based standards organization if such a method exists or you may use an industry standard pract ice as described in § 98 .234(b) to sample and analyze separator oil composition at separator pressure and temperature. (ii) Flow to storage tank direct from wells . Calculate CH 4 and CO 2 emissions using either of the methods in paragraph (j)(2)(ii)(A) or (j )(2)(ii)(B) of this section. (3) Calculation Methodology 3

. For wells with annual average daily oil production greater than or equal to 10 barrels per day that flow directly to atmospheric storage tanks without passing through a wellhead separator, calculat e annual CH 4 and CO 2 emissions by either of the methods in paragraph (j)(3) of this section: ( i 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.

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( ii 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 your well production gas/oil ratio and API gravity and assume all of the CH 4 and CO 2 in both oil and gas are emitted from the tank. (4) Calculation Methodology 4

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

- well pad separator determined by best available data. Assume all of the CH 4 and CO 2 in the oil phase is emitted from the tank. ( 5 3 ) Calculation Method ology 5 3

. Calculate CH 4 and CO 2 emissions using For well pad
gas - liquid separators and for wells flowing off a well pad without passing through a gas

- liquid separator with annual average daily throughput of oil less than 10 barrels per day use 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.
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EF i = Population emission factor for separators or wells in thousand standard cubic feet per separator or well per year, for crude oil use 4.2 for CH 4 and 2.8 for CO 2 at 60 °F and 14.7 psia, and for gas condensate use 17.6 for CH 4 and 2.8 for CO 2 at 60 °F and 14.7 psia. Count = Total number of separators or wells with annual average daily throughput less than 10 barrels per day. Count only separators or wells that feed oil directly to the storage tank. 1,000 = Conversion from thousand standard cubic feet to standard cubic feet. ( 6 4 ) Determine if the storage tank receiving your separator oil has a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (j)(1) through (j)( 5 3 ) of this section downward by the magnitude of emissions recovered usin g a vapor recovery system as determined by engineering estimate based on best available data. (ii) [Reserved] ( 7 5 ) Determine if the storage tank receiving your separator oil is sent to flare(s). (i) Use your separator flash gas volume and gas composition as determined in this section. (ii) Use the calculation method ology method of flare stacks in paragraph (n) of this section to determine your contribution to storage tank emissions from the flare. ( 8 ) Calculate ( 6 ) If you use Calculation Method 1 or Calculat ion Method 2 in paragraph (j)(1) or (j)(2) of this section, c alculate emissions from occurrences of well pad gas

- liquid separator liquid dump valves not closing during the calendar year by using Equation W

- 16 of this section. 

## ( )      

− +      

= n n n n n i s 

### T E T E CF E 8760 * 8760 * 8760 *

,

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     

= n n n o i s T E CF E * 8760 *

, , (Eq. W

- 16)

Where:

E s,i ,o = Annual total volumetric GHG emissions at standard conditions from each storage tank in cubic feet that resulted from the dump valve on the gas

- liquid separator not closing properly

. E n = Storage tank emissions as determined in Calculation Method ologie s 1, 2, or 4 in paragraphs (j)(1 ), (j)(2 ) and , if applicable, (j)(4) of this section (with wellhead separators) in standard cubic feet per year. T n = Total time the a dump valve is not closing properly in the calendar year in hours. Estimate T n is estimated by based on maintenance or , operations records (records) such that when a record shows the valve to be open improperly, it is assumed , or routine well pad inspection s that indicate the period of time when the valve was malfunctioning in open or partially open for the entire time period preceding the record starting at either the beginning of the calendar year or the previous record showing it closed properly within th e calendar year. If a subsequent record shows it is closing properly, then assume from that time forward the valve closed properly until either the next record of it not closing properly or, if there is no subsequent record, the end of the calendar year. po sition. CF n = Correction factor for tank emissions for time period T n is 3 2 .87 for crude oil production. Correction factor for tank emissions for time period T n is 5 4 .37 for gas condensate production. Correction factor for tank emissions for time period T n is 1.0 for periods when the dump valve is closed. 8,760 = Conversion to hourly emissions. ( 9 7 ) Calculate both CH 4 and CO 2 mass emissions from volumetric natural gas volumetric emissions using calculations in paragraph (v) of this section. (k) Transmissi on storage tanks

. For vent stacks connected to one or more transmission condensate storage tanks, either water or hydrocarbon, without vapor recovery, in onshore natural gas transmission compression, calculate CH 4 , and CO 2 and N 2 O annual emissions from compressor scrubber dump valve leakage as follows: specified in paragraphs (k)(1) through (k)( 4 ) of this section. If emissions from compressor scrubber dump valve leakage are routed to a flare,

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. (1) Monitor Except as specified in paragraph (k)(1)(iv) of this section, you must m onitor the tank vapor vent stack annually for emissions using one of the methods specified in paragraphs (k)(1) (i) through (k)(1)(iii) of this section. (i) Use an optical gas imaging instrument according to methods set forth in § 98 .234(a)(1 ) or by directly measuring ). (ii) M easure the tank vent directly using a flow meter or high volume sampler according to methods in § 98 .234(b) through or (d) for a duration of 5 minutes , or . (iii) Measure the tank vent using a calibrated bag according to methods in § 98 .234( b). Or
you c) for a duration of 5 minutes or unt il the bag is full, whichever is shorter. (iv) You may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak detection device according to methods set forth in § 98.234(a)(5). (2) If the tank vapors from t he vent stack are continuous for 5 minutes, or the optical gas imaging instrument or acoustic leak detection device detects a leak, then you must use one of the following two methods in either paragraph (k)(2 )(i) or (k)(2)(ii ) of this section to quantify a nnual emissions : . (i) Use a flow meter, such as a turbine meter, calibrated bag, or high flow volume sampler to estimate tank vapor volumes from the vent stack according to methods set forth in § 98.234(b) through (d). If you do not have a continuous flow measurement device, you may install a flow measuring device on the tank vapor vent stack. If the vent is directly measured for five minutes under paragraph § 98.233 (k)(1 )(ii) or (k)(1)(iii ) of this section to detect continuous leakage, this serves as the measurement.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 50 of 227 (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). ( iii 3) If a leaking dump valve is ide ntified, the leak must be counted as having occurred since the beginning of the calendar year, or from the previous test that did not detect leaking in the same calendar year. If the leaking dump valve is fixed following leak detection, the leak duration w ill 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 (k)(4)(ii) of this sectio n to quantify annual emissions

. (i ) Use the appropriate gas composition in paragr aph (u)(2)(iii) of this section. ( iv ii ) C alculate GHG CH 4 and CO 2 volumetric and mass emissions at standard conditions using calculations in paragraphs (t), (u), and (v) of this section, as applicable to the monitoring equipment used. ( 3) If the leaking dump valve (s) is fixed following leak detection , the annual emissio ns shall be calculated from the beginning of the calendar year to the time the valve (s) is repaired. (4 5 ) Calculate annual emissions from storage tanks to flares as follows: specified in paragraphs (k)( 5 )(i ) and (k)( 5 )(ii) of this section. (i) Use the stora ge tank emissions volume and gas composition as determined in paragraphs (k)(1) through (k)( 3 4 ) of this section. (ii) Use the calculation method ology 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 , CO 2 and N 2 O (when flared) well testing venting and flaring emissions as follows: Calculate CH 4 and CO 2 annual emissions from

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 51 of 227 well testing venting as specified in paragraphs (l)(1) through (l)(5) of this section. If emissions from well testing venting are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (l )(6) of this section. (1) Determine the gas to oil ratio (GOR) of the hydrocarbon production from oil well(s) tested. Determine the production rate from gas well(s) tested. (2) If GOR cannot be determined from your available data, then you must measure
qua ntities reported in this section according to one of the two procedures specified in paragraph (l)(2 ) (i) or (l)(2)(ii ) of this section to determine GOR : . (i) You may use an appropriate standard method published by a consensus

- based standards organization i f such a method exists. (ii) Or you Y ou may use an industry standard practice as described in § 98.234(b). (3) Estimate venting emissions using Equation W

- 17A (for oil wells) or Equation W

- 17B (for gas wells) of this section.

D FR GOR E n

a * *

, = (Eq. W

- 17A)

D PR E n

a *

, = (Eq. W

- 17B)

Where:

E a,n = Annual volumetric natural gas emissions from well(s) testing in cubic feet under actual conditions. GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities. FR = Flow Average annual flow rate in barrels of oil per day for the oil well(s) being tested. PR = Average annual production rate in actual cubic feet per day for the gas well(s) being tested. D = Number of days during the c alendar year , that the well(s) is tested.
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 52 of 227 (4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (5) Calculate both CH 4 and CO 2 volumetric and mass emissions from volumetric natural
gas vo lumetric emissions using calculations in paragraphs (u) and (v) of this section. (6) Calculate emissions from well testing to flares if emissions are routed to a flare as follows: specified in paragraphs (l)(6)(i) and (l)(6)(ii) of this section. (i) Use the well testing emissions volume and gas composition as determined in paragraphs (l)(1) through ( 3 l) ( 4 ) of this section. (ii) Use the calculation method ology 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 CH 4 , and CO 2 and N 2 O (when flared) annual emissions from associated gas venting and flaring emissions not in conjunction with well testing (refer to paragraph (l): Well testing venting and flaring of this section) as follows: specified in paragraphs (m)(1) through (m)(4) of this section. If emissions from associated gas venting are routed to a flare, you must calculate CH 4 , CO 2 , and N 2 O annual emissions as specified in paragraph (m)(5) of this section. (1) Determine the GOR of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, use the GOR from a cluster of wells in the same sub

- basin category shall be used

. (2) If GOR cannot be determined from your available data, then you must use one of the
two procedures specified in paragraph paragraph s (m)(2 ) (i) or (m)(2)(ii ) of this section to determine GOR : .

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 53 of 227 (i) You may use an appropriate standard method published by a consensus

- based standards organization if such a method exists. (ii) Or you Y ou may use an industry standard practice as described in § 98.234(b). (3) Estimate venting emissions using Equation W

- 18 of this section. 

# ∑ ∑

= = 

### = y

q x

p q p q p n a 

### V GOR E 1 1 , , , 

### * 

# ( ) 

# [ ] ∑ ∑

= = 

### − = y

q x

p q p q p q p n s 

### SG V GOR E 1 1 , , , , 

### * (Eq. W

- 18)

Where:

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

- basin q, in standard cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities. V p,q = Volume of oil produced, for well p in sub

- basin q, in barrels in the calendar year during time periods in which associated gas was vented or flared. SG p,q = Volume of associated gas sent to sales, for well p in sub

- basin q, in standard cubic feet of gas in the calendar year during time periods in which associated gas was vented or flared.

x = Total number of wells in sub

- basin that vent or flare associated gas. y = Total number of sub

- basins in a basin that contain wells that vent or flare associated gas. (4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. ( 5 4 ) Calculate both CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. ( 6 5 ) Calculate emiss ions from associated natural gas to flares if emissions are routed to a flare as follows: specified in paragraphs (m)( 5 )(i) and (m)( 5 )(ii) of this section. (i) Use the associated natural gas volume and gas composition as determined in paragraph (m)(1) throug h ( m) ( 4) of this section. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 54 of 227
(ii) Use the calculation method ology 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 follows: specified in paragraphs (n)(1) through (n)(9) of this section. (1) If you have a continuous flow measurement device on the flare, you must use the measured flow volumes to calculate the flare gas emissions. If all of the flare gas is not measured by the existing flow measurement device, then the flow not measured can be estimated using engineering calculations based on best available data or company records. If you do not have a continuous flow measurement device on the flare, you can install a flow measuring device on the flare or use engineering calculations based on process knowledge, company records, and best available data. (2) If you have a continuous gas composition analyzer on gas to the flare, you must use
t hese compositions in calculating emissions. If you do not have a continuous gas composition analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare as follows: specified in paragraphs (n )(2)(i) through (n)(2)(iii) of this section. (i) For onshore natural gas production, determine natural gas composition the GHG mole fraction using paragraph (u)(2)(i) of this section. (ii) For onshore natural gas processing, when the stream going to flare i s natural gas, use the GHG mole percent fraction in feed natural gas for all streams upstream of the de

- methanizer or dew point control, and GHG mole percent fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de

- methanizer overhead or dew point control for onshore natural gas processing facilities. For onshore natural

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 55 of 227 gas processing plants that solely fractionate a liquid stream, use the GHG mole percent fraction in feed natural gas liquid for all streams. (iii) For any applicable industry segment required to report to 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 hydrocarbons, then you may use a representative composition from the source for the stream determined by engineering calculation based on process knowledge and best available data. (3) Determine flare combustion efficiency from manufacturer. If not availab le, assume that flare combustion efficiency is 98 percent. (4) Calculate Convert GHG volumetric emissions to standard conditions using calculations in paragraph (t) of this section. (5) Calculate GHG volumetric emissions from flaring at actual standard cond itions using Equations W

- 19 , W

- 20, and W

- 21 20 of this section. 

## ( ) ( ) 4 4 , * 1 * CH a CH a X V combusted un E η
− = − 

### ( ) 4 , 4 * *1 * s CH s CH L U E VX Z Z η = −+     (Eq. W

- 19) 

## ( ) 2 2 , * CO a CO a X V combusted un E = − 

## ( ) 5 , 2 2 1 * *** * s s CO CO s j j L j E VX VY R Z η

= = + 

## ∑ (Eq. W

- 20 ) 

# ( ) ( ) ∑

= 

### = 5

1 2 , 

### * * * J j j a CO a 

### R Y V combusted E η (Eq. W

- 21)

Where:

E a,CH4 (un

- combusted) = Contribution of annual un

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

- combusted) = Contribution of annual un

- combusted CO 2 emissions from flare stack in cubic feet, under actual conditions. E a,CO2 (combusted) = Contribution of annual combusted CO 2 emissions from flare stack in cubic feet, under actual conditions. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 56 of 227

E s,CH4 = Annual CH 4 emissions from flare stack in cubic feet, at standard conditions. E s,CO2 = Annual CO 2 emissions from flare stack in cubic feet, at standard conditions. V a V s = Volume of gas sent to flare in standard cubic feet, during the year as determined in paragraph (n)(1) of this section

. η = Fraction of Flare combustion efficiency, expressed as f raction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, η is zero. X CH4 = Mole fraction of CH 4 in the feed gas to the flare as determined in paragraph (n)(2) of this section. X CO2 = Mole fraction of CO 2 in the feed gas to the flare as determined in paragraph (n )(2) of this section

. Z U = Fraction of the feed gas sent to an un

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

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

- Z U ). Y

j = Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes

- plus ). ) in the feed gas to the flare as determined in paragraph (n)(1) of this section. R

j = Number of carbon atoms in the gas hydrocarbon constituent j in the feed gas to the flare : 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes

- plus). ( 5) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section. ( 6) Calculate both CH 4 and CO 2 mass emissions from volumetric CH 4 and CO 2 emissions using calculation in paragraph (v) of this section. ( 7 ) [Reserved] (8 ) Calculate N 2 O emissions from flare stacks using Equation W

- 40 in paragraph (z) of this section. ( 9 8 ) If you operate and maintain a CEMS that has both a CO 2 concentration monitor and volumetric flow rate monitor for the combustion gases from the flare , you must calculate only
CO 2 emissions for the flare. You must follow the Tier 4 Calculation Method ology Method and all This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 57 of 227 associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). If a CEMS is used to calculate flare stack emissions, the requirements specifie d in paragraphs (n)(1) through (n)( 7 ) are not required. If a CO 2 concentration monitor and volumetric flow rate monitor are not available, you may elect to install a CO 2 concentration monitor and a volumetric flow rate monitor that comply with all of the r equirements specified for the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion). ( 10 9 ) The flare emissions determined under this paragraph (n) of this section must be corrected for flare emissions calculated and reported under other paragraphs of this section to avoid double counting of these emissions. (11) If source types in §98.233 use Equations W

- 19 through W

- 21 of this section, use estimate of emissions under actual conditions for the parameter, V a , in these equations. (o) Centrifugal compressor venting

. If you are required to report emissions from centrifugal compressor venting as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (o)(5) of this section; perform calculations specified in paragraphs (o)(6) through (o)(9) of this section; and calculate CH 4 and
CO 2 mass emissions as specified in parag raph (o)(11) of this section. If emissions from a compressor source are routed to a flare, paragraphs (o)(1) through (o)(11) of this section do not apply and instead you must calculate CH 4 , CO 2 , and N 2 O emissions as specified in paragraph (o)(12) of this s ection. If emissions from a compressor source are captured for fuel use or are routed to a thermal oxidizer, paragraphs (o)(1) through (o)(12) of this section do not apply and instead you must calculate and report emissions as specified in subpart C of thi s part. If

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 58 of 227 emissions from a compressor source are routed to vapor recovery, paragraphs (o)(1) through (o)(12) of this section do not apply. If you are required to report emissions from centrifugal compressor venting at an onshore petroleum and natural gas production facility as specified in § 98.232(c)(19), you must calculate volumetric emissions as specified in paragraph (o)(10) of this section; and calculate CH 4 and CO 2 mass emissions as specified in paragraph (o)(11) of this section. (1) General requirem ents for conducting volumetric emission measurements

. You must conduct volumetric emission measurements on each centrifugal compressor as specified in this paragraph. Compressor sources (as defined in § 98 .238) without manifolded vents must use a measurement method specified in paragraph (o)(1)(i) or (o)(1)(ii) of this section. Manifolded compressor sources (as defined in § 98 .238) must use a measurement method specified in paragraph (o)(1)(i), (o)(1)(ii), (o)(1)(iii), or (o)(1)(i v) of this section. (i) Centrifugal compressor source as found measurements. Measure venting from each compressor according to either paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section at least once annually, based on the compressor mode (as defined i n § 98 .238) in which the compressor was found at the time of measurement, except as specified in paragraphs (o)(1)(i)(C) and (o)(1)(i)( D ) of this section. If additional measurements beyond the required annual testing are performed (including duplicate meas urements or measurement of additional operating modes), then all measurements 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 i n operating

- mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (o)(2)(i)(A) or (o)(2)(i)(B) of this section and, if the compressor has wet seal oil

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 59 of 227 degassing vents, measure vol umetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section. (B) For a compressor measured in not

- operating

- depressurized

- mode, you must measure volumetric emissions from isolation valve leakage as specified in either paragraph (o)(2)(i)(A), (o)(2)(i)(B), or (o)(2)(i)(C) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode. (C) You must measure the com pressor as specified in paragraph (o)(1)(i)(B) of this section at least once in any three consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If three consecutive calendar years occur without measuring the compres sor 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 not apply if the compressor has b lind flanges in place throughout the reporting year. 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 schedule d shutdown does not include instances when 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 all existing compressors. For only the first year of operation of new compressors, calculate emissions according to paragraph (o)(6)(ii) of this section. (ii) Centrifugal compressor source continuous monitoring. Instead of measuring the
comp ressor source according to paragraph (o)(1)(i) of this section for a given compressor, you

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 60 of 227 may elect to continuously measure volumetric emissions from a compressor source as specified
in paragraph (o)(3) of this section. (iii) Manifolded centrifugal compre ssor source as found measurements. For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98 .238), instead of measuring the compressor source according to paragraph (o)(1)(i), (o)(1)(ii), or (o)(1)(iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting measurements at the 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 (o)(1)(iii)( B ) of this section. (A) A minimum of one measurement must be taken for ea ch manifolded group of compressor sources in a calendar year. (B) The measurement may be performed while the compressors are in any compressor mode. (iv) Manifolded centrifugal compressor source continuous monitoring. For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (o)(1)(i), (o)(1)(ii), or (o)(1)(iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded gr oup of
compressor sources as specified in paragraph (o)(5) of this section. (2) Methods for performing as found measurements from individual centrifugal
compressor sources . If conducting measurements for each compressor source, you must determine the volu metric emissions from blowdown valves and isolation valves as specified in paragraph (o)(2)(i) of this section, and the volumetric emissions from wet seal oil degassing
vents as specified in paragraph (o)(2)(ii) of this section.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 61 of 227
(i) For blowdown valves on compressors in operating

- mode and for isolation valves on compressors in not

- operating

- depressurized

- mode, determine the volumetric emissions using one of the methods specified in paragraphs (o)(2)(i)(A) through (o)(2)(i)(D ) of this section. (A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98 .234(c) and § 98 .234(d), respectively. (B) Determine the volumetric flow at standard conditions from t he blowdown vent using a temporary meter such as a vane anemometer according 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 forth in § 98 .234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98 .234(a), then you must use one of the methods specified in paragraph (o)(2)(i)(A) through (o)(2)(i)( C ) 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 whenever a leak is detected according to the methods. (ii) For wet seal oil degassing vents in operating

- mode, determine vapor volumes at standard conditions, using a temporary meter such as a vane anemometer or permanent flow meter according to methods set forth in § 98 .234(b). (3) Methods for continuous measurement from individual centrifugal compressor sources

. If you elect to conduct continuous volumetric emission measurements for an individual

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 62 of 227

compressor source as specified in paragraph (o)(1)(ii) of this section, you must measure volumetric emissions as specified in paragraphs (o)(3)(i) and (o)(3)(ii) of this section. (i) Continuously measure the volumetric flow for the individual compressor source at standard conditions using a permanent meter according to methods set forth in § 98 .234(b). (ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (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 ca lculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (4) Methods for performing as found measurements from manifolded groups of centrifugal compressor sources . If conducting measurements for a manifolded group of compressor sources, you must measure volumetric emissions as specified in paragraphs (o)(4)(i) and (o)(4)(ii) of this section. (i) Measure at a single point in the manifold downstream of all compressor inputs and , if practical, prior to comingl ing with other non

- compressor emission sources. (ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraphs (o)(4)(ii)(A) through (o)(4)(ii)( E ) of this section. (A) A temporary meter s uch as a vane anemometer according the methods set forth in § 98 .234(b). (B) Calibrated bagging according to methods set forth in § 98 .234(c). (C) A high volume sampler according to methods set forth § 98 .234(d). (D) A n acoustic leak detection device accor ding to methods set forth in § 98 .234(a)(5)

. (E) You may choose to use any of the methods set forth in § 98 .234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98 .234(a), then you must

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 63 of 227

use one of the meth ods specified in paragraph (o)(4 )(i i)(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 whenever a leak is detected according to the method. (5) Methods for continuous measurement from manifolded groups of centrifugal
compressor sources . If you elect to conduct continuous volumetric emission measurement s for a manifolded group of compressor sources as specified in paragraph (o)(1)(iv) of this section, you must measure volumetric emissions as specified in paragraphs (o)(5)(i) through (o)(5)(iii) of this section. (i) Measure at a single point in the manifold downstream of all compressor inputs and , if practical, prior to comingl ing with other non

- compressor emission sources. (ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a per manent meter according to methods set forth in § 98 .234(b). (iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (6) Method for calculating volumetric GHG emissions from as found me asurements for individual centrifugal compressor sources . For compressor sources measured according to

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 64 of 227 paragraph (o)(1)(i) of this section, you must calculate annual GHG emissions from the
compressor sources as specified in paragraphs (o)(6)(i) through (o) (6)( iv ) of this section. (i) Using Equation W

- 21 of this section, calculate the annual volumetric GHG emissions for each centrifugal compressor mode

- source combination specified in paragraphs (o)(1)(i)(A) and (o)(1)(i)(B) of this section that was measured during the reporting year. Calculate CH 4 , CO 2 and N 2 O (when flared) emissions from both wet seal and dry seal centrifugal compressor vents as follows: (1) For each centrifugal compressor covered by § 98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) you must conduct an annual measurement in the operating mode in which it is found. Measure emissions from all vents (including emissions manifolded to common vents) including wet seal oil degassing vents, unit isolation valve vents, and blowdown valve vents. R ecord emissions from the following vent types in the specified compressor modes during the annual
measurement. (i) Operating mode, blowdown valve leakage through the blowdown vent, wet seal and dry seal compressors. (ii) Operating mode, wet seal oil degass ing vents. (iii) Not operating, depressurized mode, unit isolation valve leakage through open blowdown vent, without blind flanges, wet seal and dry seal compressors. (A) For the not operating, depressurized mode, each compressor must be measured at least once in any three consecutive calendar years. If a compressor is not operated and has blind flanges in place throughout the 3 year period, measurement is not required in this mode. If the compressor is in standby depressurized mode without blind flanges in place and is not operated throughout the 3 year period, it must be measured in the standby depressurized mode.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 65 of 227 (2) For wet seal oil degassing vents, determine vapor volumes sent to an atmospheric vent or flare, using a temporary meter such as a vane anemo meter or permanent flow meter according to 98.234(b) of this section. If you do not have a permanent flow meter, you may install a permanent flow meter on the wet seal oil degassing tank vent. (3) For blowdown valve leakage and unit isolation valve leakage to open ended vents, you can use one of the following methods: Calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. For through valve leakage, such as isolation valves, you may use an acousti c leak detection device according to methods set forth
in § 98.234(a). If you do not have a flow meter, you may install a port for insertion of a temporary meter, or a permanent flow meter, on the vents. (4) Estimate annual emissions using the flow measurem ent and Equation W

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

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

− = m i m m s m i s GHG T MT E

, , , , * * = (Eq. W

- 22 21 )

Where:

E s,i,m = Annual volumetric GHG i (either CH 4 or CO 2 ) volumetric ) emissions for measured compressor mode

- source combination m, at standard conditions, in cubic feet. MT m = Measured MT s,m = Volumetric gas emissions for measured compressor mode

- source combination m, in standard cubic feet per hour , measured according to paragraph (o)(2) of this section. If multiple measurements 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 calendarreporting year , in hours. M i GHG i ,m = Mole fraction of GHG i in the vent gas for measured compressor mode

- source combination m ; use the appropriate gas compositions in paragraph (u)(2) of this section.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 66 of 227

B m = Fraction of operating time that the vent gas is sent to vapor recovery or fuel gas as de termined by keeping logs of the number of operating hours for the vapor recovery system and the time that vent gas is directed to the fuel gas system or sales.

m = Compressor mode

- source combination specified in paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of th is section that was measured for the reporting year. (5) Calculate annual emissions from each centrifugal compressor using Equation W

- 23 of this section. (ii) Using Equation W

- 22 of this section, calculate the annual volumetric GHG emissions from each cent rifugal compressor mode

- source combination specified in paragraph (o)(1)(i)(A) and (o)(1)(i)(B) of this section that was not measured during the reporting year.

, , * * sim m m i E EF T GHG = (Eq. W

- 23)

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 conditions, in cubic feet. Annual total volumetric GHG emissions at standard conditions from each centrifugal compressor for mode

- source co mbination m, in cubic feet. EF s, m = Reporter emission factor for compressor mode

- source combination each mode m, in standard cubic feet per hour, from Equation W

- 24 of this section as calculated in paragraph (o)( 6 )(iii) if this section

. T m = Total time in h ours per year the compressor was in the unmeasured each mode

- source combination m , as listed in paragraph (o)(1)(i) through (o)(1)( iii). for which E s,i,m is being calculated in the reporting year, in hours. GHG i = For onshore natural gas processing facilities, concentration of GHG i , CH 4 or CO 2 , in produced natural gas or feed natural gas; for other facilities listed in § 98.230(a)(4) through (a)(8),GHG i equals 1. GHG i,m = Mole fraction of GHG i in the vent gas for unmeasured compressor mode

source com bination 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 not measured in the reporting year. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 67 of 227 (iii) Using Equation W

- 23 of this section, develop an emission factor for each compressor mode

- source combination specified in paragraph (o)(1)(i)(A) and (o)(1)(i)(B) of this section. These emission factors must be calculated annually and used in Equation W

- 2 2 of this section to determine volumetric emissions from a centrifugal compressor in the mode

- source combinations that were not measured in the reporting year. (6) You shall use the flow measurements of operating mode wet seal oil degassing vent, operating mode blow down valve vent and not operating depressurized mode isolation valve vent for all the reporter's compressor modes not measured in the calendar year to develop the following emission factors using Equation W

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

, 1 m Count
m p

p m m 

### MT EF Count = 

### = 

# ∑

m Count

p p m s

m s Count MT EF m 

## ∑

= = 1 , ,

, (Eq. W

- 24) 23)

Where:
EF m EF s ,m = Reporter emission factors factor to be used in Equati on W

- 2 2 of this section for compressor mode

- source combination m, in standard cubic feet per hour. The reporter emission factor must be based on all compressors measured in compressor mode

- source combination m in the current reporting year and the preceding two reporting years. in the three modes m (as listed in paragr aph (o)(1)(i) through (o)(1)(iii)) in cubic feet per hour. MT m,p = Flow measurements from all centrifugal compressor sources in each mode

source combination , m, for each measured compressor, p, in standard cubic feet per hour

. 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 combination m for compressor p in the current reporting year and the preceding two reporting years. Count m = Total number of compressors measured in compressor mode

- source combination m in the current reporting year and the preceding two reporting years .
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 68 of 227

m = Compresso r mode

- source combination as listed specified in paragraphs paragraph (o)(1)(i ) through )(A) or (o)(1)( iii).( i )(B) of this section. (i) The emission factors must be calculated annually. You must use all measurements from the current calendar year and the pre ceding two calendar years, totaling three consecutive calendar years of measurements in paragraph (o)(6) of this section. (ii) [Reserved] (iv) The reporter emission factor in Equation W

- 23 of this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator. (7) Method for calculating volumetric GHG emissions from continuous monitoring of individual centrifugal compressor sources . For compressor sources measured according to paragraph (o)( 1)(ii) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (o)(3) of this section and calculate annual volumetric GHG emissions associated with the compressor source using Equation W

- 24A of this

sec tion.

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.

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(8) Method f or 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

vo lumetric GHG emissions using Equation W

- 24B of this section. If the centrifugal compressors included in the manifolded group of compressor sources share the manifold with reciprocating compressors, you must follow the procedures in either this paragraph ( o )(8) or paragraph ( p )(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

- 24B)

Where:

E s,i,g = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions for manifolded group of compressor sources g, at standard conditions, in cubic feet. T g = Total time the manifolded group of compressor sources g had potential for emissions in the reporting year, in hours. Include all time during which at least one compressor source i n the manifolded group of compressor sources g was in a mode

- source combination specified in either 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 vo lumetric gas emissions of all measurements performed in the reporting year according to paragraph (o)(4) of this section for the manifolded group of compressor sources g, in standard cubic feet per hour. GHG i,g = Mole fraction of GHG i in the vent gas for manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section. (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 emiss ions associated with each manifolded group of
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 70 of 227 compressor sources using Equation W

- 24C of this section. If the centrifugal compressors included in the manifolded group of compressor sources share the manifold with reciprocating compressors, you must follow the procedures in either this paragraph (o)(9) or paragraph (p)(9) of this section to calculate emissions from the manifolded group of compressor sources.

g i g s g i s GHG Q E

, , , , * = (Eq. W

- 24C)

Where:

E s,i,g = Annual volumetric GHG i (either CH 4 or CO 2 ) emissions from manifolded group of compressor sources g, at standard conditions, in cubic feet. Q s,g = Volumetric gas emissions from manifolded group of compressor sources g, for reporting year, in standard cubic feet. GHG i,g = Mole fraction of GHG i in the vent gas for measured manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section. (7) Onshore petroleum and natural gas production shall calculate emissions from centrifugal compressor wet seal o il degassing vents as follows: (10) Method for calculating volumetric GHG emissions from wet seal oil degassing vents at an onshore petroleum and natural gas production facility . You must calculate emissions from centrifugal compressor wet seal oil degassing vents at an onshore petroleum and natural gas production facility using Equation W

- 25 of this section.

i i s EF Count E *

, = (Eq. W

- 25)

Where:

E s,i = Annual total volumetric GHG GHG i (either CH 4 or CO 2 ) emissions at standard conditions from centrifugal compressor wet seals , at standard conditions, in cubic feet. Count = Total number of centrifugal compressors for the reporter that have wet seal oil degassing vents

. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 71 of 227

EF i ,s = Emission factor for GHG i . Use 1.2 × 10 7 standard cubic feet per year p er compressor for CH 4 and 5.30 × 10 5 standard cubic feet per year per compressor for CO 2 at 60 °F and 14.7 psia. ( 8) Calculate 11) Method for converting from volumetric to mass emissions . You must calculate both CH 4 and CO 2 mass emissions from volumetric em issions using calculations in paragraph (v) of this section. (9) Calculate emissions from seal oil degassing vent vapors to flares as follows: (i) Use the seal oil degassing vent vapor volume and gas composition as determined in paragraphs (o)(5) of this s ection. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine degassing vent vapor emissions from the flare. (12) General requirements for calculating volumetric GHG emissions from centrifugal
compressors routed to flares . You must calculate and report emissions from all centrifugal compressor sources that are routed to a flare as specified in paragraphs (o)(12)(i) through (o)(12)(iii) of this section. ( i ) Paragraphs (o)(1) through (o)(11) of this section a re not required for compressor sources that are routed to a flare. (ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as speci fied
in § 98 .236(n), without subtracting emissions attributable to compressor sources from the flare. (iii) Report all applicable activity data for compressors with compressor sources routed to flares as specified in § 98 .236(o). (p) Reciprocating compress or venting

. Calculate CH 4 and CO 2 emissions fr om all reciprocating compressor vents as follows. For each reciprocating compressor covered in

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§ 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must conduct an annual measurement for each compressor in the mode in which it is found during the annual measurement, except as specified in paragraph (p)(9) of this section. Measure emissions from (including emissions manifolded to common vents) reciprocating rod packing vents, unit isolation valve vents, and blow down valve vents. Record emissions from the following vent types in the specified compressor modes during the annual measurement as follows: (1) Operating or standby pressurized mode, blowdown vent leakage through the blowdown vent stack. (2) Operating mod e, reciprocating rod packing emissions. (3) Not operating, depressurized mode, unit isolation valve leakage through the blowdown vent stack, without blind flanges. (i) For the not operating, depressurized mode, each compressor must be measured at least

onc e in any three consecutive calendar years if this mode is not found in the annual measurement. If a compressor is not operated and has blind flanges in place throughout the 3 year period, measurement is not required in this mode. If the compressor is in st andby depressurized mode without blind flanges in place and is not operated throughout the 3 year period, it must be measured in the standby depressurized mode. (ii) [Reserved] (4) If reciprocating rod packing and blowdown vent are connected to an open

- end ed vent line use one of the following two methods to calculate emissions: (i) Measure emissions from all vents (including emissions manifolded to common vents) including rod packing, unit isolation valves, and blowdown vents using either calibrated bagging

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 73 of 227 or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. (ii) Use a temporary meter such as a vane anemometer or a permanent meter such as an orifice meter to measure emissions from all vents (including emissions m anifolded to a common vent) including rod packing vents and unit isolation valve leakage through blowdown vents according to methods set forth in § 98.234(b). If you do not have a permanent flow meter, you may install a port for insertion of a temporary met er or a permanent flow meter on the vents. For through

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

- 26 of this section. Calculate CH 4 and CO 2 If you are required 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 specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (p)(5) of this section; perform calculations

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 74 of 227 specified in paragraphs (p)(6) through (p)(9) of this section; and calculate CH 4 and CO 2 mass emissions as specified in paragraph (p)(11) of this section. If emissions from a compressor source are routed to a flare, paragraphs (p)(1) through (p)(11) of this section do not apply and instead you must calculate CH 4 , CO 2 , and N 2 O emissions as specified in paragraph (p)(12) of this section. If emissions from a compressor source a re captured for fuel use or are routed to a thermal oxidizer, paragraphs (p)(1) through (p)(12) of this section do not apply and instead you must calculate and report emissions as specified in subpart C of this part. If emissions from a
compressor source a re routed to vapor recovery, paragraphs (p)(1) through (p)(12) of this section do not apply. If you are required to report emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility as specified in § 98.232( c)(11), you must calculate volumetric emissions as specified in paragraph (p)(10) of this section; and calculate
CH 4 and CO 2 mass emissions as specified in paragraph (p)(11) of this section. (1) General requirements for conducting volumetric emission measu rements

. You must conduct volumetric emission measurements on each reciprocating compressor as specified in this paragraph. Compressor sources (as defined in § 98 .238) without manifolded vents must use a measurement method specified in paragraph (p)( 1)(i) or (p)(1)(ii) of this section. Manifolded compressor sources (as defined in § 98 .238) must use a measurement method specified in paragraph (p)(1)(i), (p)(1)(ii), (p)(1)(iii), or (p)(1)(iv) of this section. (i) Reciprocating compressor source as found measurements. Measure venting from each compressor according to either paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section at least once annually, based on the compressor mode (as defined in § 98 .238) in which the compressor was found at the time of measurement, except as specified in paragraph s (p)(1)(i)(D) and (p)(1)(i)(E) of this section. If additional measurements beyond the required annual testing

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 75 of 2 27 are performed (including duplicate measurements or measurement of additional operating modes), then all measurements 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, you must measure volumetric emi ssions from blowdown valve leakage through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (p)(2)(i)(B) of this section, and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) of this section

. (B) For a compressor measured in standby

- pressurized

- mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (p)(2)(i)(B) of this section. (C) For a compressor mea sured in not

- operating

- depressurized

- mode, you must measure volumetric emissions from isolation valve leakage as specified in either paragraph (p)(2)(i)(A), (p)(2)(i)(B), or (p)(2)(i)(C) of this section. If a compressor is not operated and has blind flange s in place throughout the reporting period, measurement is not required in this compressor mode. (D) You must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at least once in any three consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If there is no scheduled shutdown within three consecutive calendar years, you must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at the next scheduled depressurized shut down. 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 schedule d shutdown does not include instances when a compressor is taken offline due to a de crease in demand but must remain available.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 76 of 227 (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 all existing compressors. For onl y the first year of operation of new compressors, calculate emissions according to paragraph (p)(6)(ii) of this section. (ii) Reciprocating compressor source continuous monitoring. Instead of measuring the compressor source according to paragraph (p)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric emissions from a compressor sou rce 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 group of compressor sources (as defined in § 98 .238), instead of measuring the compressor source according to paragraph (p)(1)(i), (p)(1)(ii), or (p)(1)(iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting measurements at the common vent stack as specified in paragraph (p)(4) of this section. The measurements must be conducted at the frequency specified in paragraphs (p)(1)(iii)(A) and (p)(1)(iii)( B ) of this section. (A) A minimum of one measurement must be taken for ea ch manifolded group of compressor sources in a calendar year. (B) The measurement may be performed while the compressors are in any compressor mode. (iv) Manifolded reciprocating compressor source continuous monitoring. For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (p)(1)(i), (p)(1)(ii), or (p)(1)(iii) of this

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 77 of 227 section, you may elect to continuously measure combined volumetric emissions from the manifolded g roup of compressors sources as specified in paragraph (p)(5) of this section. (2) Methods for performing as found measurements from individual reciprocating
compressor sources . If conducting measurements for each compressor source, you must determine the v olumetric emissions from blowdown valves and isolation valves as specified in paragraph (p)(2)(i) of this section. You must determine the volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (p)(2)(iii) of this sectio n. (i) For blowdown valves on compressors in operating

- mode or standby

- pressurized

mode, and for isolation valves on compressors in not

- operating

- depressurized

- mode, determine the volumetric emissions using one of the methods specified in paragraphs (p)(2) (i)(A) through (p)(2)(i)(D ) of this section. (A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98 .234(c) and § 98 .234(d), respectively. (B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer, according to methods set forth in § 98 .234(b). (C) 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 forth in § 98 .234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98 .234(a), then you must use one of the methods specified in paragraphs (p)(2)(i)(A) through (p)(2)(i)(C) 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

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methods in § 98.234(a), emissions ar e detected whenever a leak is detected according to the method. (ii) For reciprocating rod packing equipped with an open

- ended vent line on compressors in operating

- mode, determine the volumetric emissions using one of the methods specified in paragraphs ( p)(2)(ii)(A) through (p)(2)(ii)( C ) of this section. (A) Determine the volumetric flow at standard conditions from the open

- ended vent line using calibrated bagging or high volume sampler according to methods set forth in § 98 .234(c) and § 98 .234(d), respec tively. (B) Determine the volumetric flow at standard conditions from the open

- ended vent line using a temporary meter such as a vane anemometer, according to methods set forth in § 98 .234(b). (C) You may choose to use any of the methods set forth in § 9 8 .234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98 .234(a), then you must use one of the meth ods specified in paragraph (p)(2 )(i i)(A) and (p)(4)(ii)(B ) of this section. If emissions are not detected using the met hods 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 whenever a leak is detected according to the method. (iii) For recipro cating rod packing not equipped with an open

- ended vent line on compressors in operating

- mode, you must determine the volumetric emissions using the method specified in paragraphs (p)(2)(iii)(A) and (p)(2)(iii)(B) of this section. (A) You must use the meth ods described in § 98 .234(a) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or for compressors with a

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 79 of 227 closed distance piece, conduct annual detection of gas emissions from the rod packing vent, distan ce piece vent, compressor crank case breather cap, or other vent emitting gas from the rod packing. (B) You must measure emissions found in paragraph (p)(2)(iii)(A) of this section using an appropriate meter, calibrated bag, or high volume sampler accordin g to methods set forth in § 98.234(b), (c), and (d), respectively. (3) Methods for continuous measurement from individual reciprocating compressor

sources . If you elect to conduct continuous volumetric emission measurements for an individual
compressor source as specified in paragraph (p)(1)(ii) of this section, you must measure volumetric emissions as specified in paragraphs (p)(3)(i) and (p)(3)(ii) of thi s section. (i) Continuously measure the volumetric flow for the individual compressor sources at standard conditions using a permanent meter according to methods set forth in § 98 .234(b). (ii) If compressor blowdown emissions are included in the metered e missions 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 th is section for blowdown vent stacks. (4) Methods for performing as found measurements from manifolded groups of reciprocating compressor sources . If conducting measurements for a manifolded group of compressor sources, you must measure volumetric emissions as specified in paragraphs (p)(4)(i) and (p)(4)(ii) of this section. (i) Measure at a single point in the manifold downstream of all compressor inputs and , if practical, prior to comingl ing with other non

- compressor emission sources.

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(ii) Determine the v olumetric flow at standard conditions from the common stack using one of the methods specified in paragraph (p)(4)(ii)(A) through (p)(4)(ii)( E ) of this section

. (A) A temporary meter such as a vane anemometer according the methods set forth in § 98 .234(b)

. (B) Calibrated bagging according to methods set forth in § 98 .234(c). (C) A high volume sampler according to methods set forth § 98 .234(d). (D) A n 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 forth in § 98 .234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98 .234(a), then you must use one of the meth ods specified in paragraph (p)(4 )(i i)(A) through (p)(4)(ii)(D ) of this section. If e missions 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 whenever a leak is detected acc ording to the method. (5) Methods for continuous measurement from manifolded groups of reciprocating
compressor sources . If you elect to conduct continuous volumetric emission measurements for a manifolded group of compressor sources as specified in paragraph (p)(1)(iv) of this section, you must measure volumetric emissions as specified in paragraphs (p)(5)(i) through (p)(5)(iii) of this section. (i) Measure at a single point in the manifold downstream of all compressor inputs and , if practical, prio r to comingl ing with other non

- compressor emission sources.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 81 of 227 (ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98 .234(b). (iii) I f compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (6) Method for calculating volumetric GHG emissions from as found measurements for individual reciprocating compressor sources. For comp ressor sources measured according to paragraph (p)(1)(i) of this section, you must calculate GHG emissions from the compressor

sources as specified in paragraphs (p)(6)(i) through (p)(6)( iv ) of this section. (i) Using Equation W

- 26 of this section, calcula te the annual volumetric GHG emissions for each reciprocating compressor mode

- source combination specified in paragraphs (p)(1)(i)(A) through (p)(1)(i)(C) of this section that was measured during the reporting year.

m i m m m i s M T MT E

, , , * * = m i m m s m i s GHG T MT E

, , , , * * = (Eq. W

- 26)

Where:

E s,i,m = Annual GHG i volumetric GHG i (either CH 4 or CO 2 ) volumetric ) emissions for measured compressor mode

- source combination m, at standard conditions, in cubic feet. MT m = Measured MT s,m = Volumetric gas emissions for measured compressor mode

- source combination m, in standard cubic feet per hour , measured according to paragraph (p)(2) of this section. If multiple measurements are performed for a given mode

- source combination m, use the average of all measurements

. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 82 of 227

T m = Total time the compressor is in the mode

- source combination m, for which E s,i,m is being calculated , in the calendarreporting year , in hours. M i GHG i ,m = Mole fraction of GHG i GHG i in the vent gas for measured compressor mode

source combi nation m ; use the appropriate gas compositions in paragraph (u)(2) of this section.

m = Compressor mode

- source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was measured for the reporting year. (7) Calc ulate annual emissions from each reciprocating compressor using Equation W

- 27 of this section. (ii) Using Equation W

- 27 of this section, calculate the annual volumetric GHG emissions from each reciprocating compressor mode

- source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section that was not measured during the reporting year.

, , * * sim m m i E EF T GHG = (Eq. W

- 27)

m i m m s m i s GHG T EF E

, , , , * * = (Eq. W

- 27)

Where:

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

- source combination m, in cubic feet. Annual volumetric GHG i (either CH 4 or CO 2 ) emissions for unmeasured compressor mode

- source combination m, at standard conditions, in cubic feet. EF m EF s,m = Reporter emission factor for each compressor mode , - source combination m, in standard cubic feet per hour, from as calculated in paragraph (p)(6)(iii) of this section. T m = Total time in hours per year the compressor was in each mode, m, as listed in paragrap h (p)(1) through (p)(3). Total time the compressor was in the unmeasured mode

- source combination m, for which E s,i,m is being calculated in the reporting year, in hours.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 83 of 227

GHG i = For onshore natural gas processing facilities, concentration of GHG i, CH 4 or CO 2 , in produced natural gas or feed natural gas; for other facilities listed in § 98.230(a)(4) through (a)(8), GHG i equals 1. GHG i,m = Mole fraction of GHG i in the vent gas for unmeasured compressor mode

source combination m; use the appropriate gas compos itions in paragraph (u)(2) of this section.

m = Compressor mode as listed in paragraph (p)(1) through (p)(3). Compressor mode

- source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was not measured in the reporting year. (i) You shall use the flow meter readings from measurements of operating and standby pressurized blowdown vent, operating mode vents, not operating depressurized isolation valve vent for all the reporter's compressor modes not measured in t he calendar year to develop the following emission factors using Equation W

- 28 of this section for each mode as listed in paragraph (p)(1) through (p)(3). (iii) Using Equation W

- 28 of this section , develop an emission factor for each compressor mode

- source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section. These emission factors must be calculated annually and used in Equation W

- 27 of this section to determine volumetric emissions from a reciprocating compressor in the mode

source combinations that were not measured in the reporting year

.

, 1 m Count
m p

p m m 

### MT EF Count = 

### = 

# ∑

m Count

p p m s

m s Count MT EF m 

## ∑

= = 1 , ,

, (Eq. W

- 28)

Where:

EF m EF s ,m = Reporter emission factors for compressor in the three modes, m, in cubic feet per hour. Reporter emission factor to be used in Equation W

- 27 of this section for compressor mode

- source combination m, in standard cubic feet per hour. The reporter emission factor must be based on all compressors measured in
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 84 of 227 compressor mode

- source combinatio n m in the current reporting year and the preceding two reporting years. MT m,p = Flow measurements from all reciprocating compressor sources in each mode

source combination, m, for each measured compressor, p, in standard cubic feet per hour. MT s,m,p = Ave rage 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

- sou rce combination m for compressor p in the current reporting year and the preceding two reporting years. Count m = Total number of compressors measured in each mode, m compressor mode

source combination m in the current reporting year and the preceding two re porting years

. m = Compressor mode

- source combination as listed specified in paragraph (p)(1 ) (i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. through (p)(3). (A) You must combine emissions for blowndown vents, measured in the operating and standby pressurized modes. (B) The emission factors must be calculated annually. You must use all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar years of measurements. (ii) [Reserved] (8) Deter mine if the reciprocating compressor vent vapors are sent to a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (p)(7) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by en gineering estimate based on best available data. (ii) [Reserved] (9) Onshore petroleum and natural gas production shall calculate emissions from reciprocating compressors as follows:
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 85 of 227 (iv) The reporter emission factor in Equation W

- 28 of this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or oper ator. (7) Method for calculating volumetric GHG emissions from continuous monitoring of individual reciprocating compressor sources . For compressor sources measured according to paragraph (p)( 1)(ii) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (p)(3) of this section and calculate annual volumetric GHG emissions associated with the compressor source using Equation W

- 29A of this

sec tion.

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. (8) Method fo r calculating volumetric GHG emissions from as found measurements of manifolded groups of reciprocating compressor sources. For manifolded groups of compressor sources measured according to paragraph (p)(1)(iii) of this section, you must calculate annual
G HG 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 paragraph (p)(8) or pa ragraph (o)(8) of this section to calculate emissions from the manifolded group of compressor sources. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 86 of 227

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 conditions, in cubic feet. T g = Total time the manifolded group of compressor sources g had potential for emissions in the reporting year, in hours. Include all time during which at least one compressor source i n the manifolded group of compressor sources g was in a mode

- source combination specified in either 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 vo lumetric gas emissions of all measurements performed in the reporting year according to paragraph (p)(4) of this section for the manifolded group of compressor sources g, in standard cubic feet per hour. GHG i,g = Mole fraction of GHG i in the vent gas for manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section. (9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of reciprocating compressor sources . For a manifolded group of compressor sources measured according to paragraph (p)(1)(iv) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (p)(5) of this section and calculate annual volumetric GHG emissions associated with each manifolded group of compressor sources using Equation W

- 29C of this section. If the reciprocating compressors included in the manifolded group of compresso r sources share the manifold with centrifugal compressors, you must follow the procedures in either this paragraph (p)(9) or paragraph (o)(9) of this section to calculate emissions from the manifolded group of compressor sources.

g i g s g i s GHG Q E

, , , , * = ( Eq. W

- 29C)

Where:

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 87 of 227

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

- 29D of this section.

s i i s EF Count E

, , *

= (Eq. W

- 29 D )

Where:

E s,i = Annual total volumetric GHG GHG i (either CH 4 or CO 2 ) emissions at standard conditions from reciprocating compressors , at standard conditions, in cubic feet. Count = Total number of reciprocating compressors for the reporter

. 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. ( 10) Estimate 11) Method for converting from volumetric to mass emissions . You must calculate both CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in paragraphs (u) and paragraph (v) of this section. (12) General requirements for calculating volumetric GHG emissions from reciprocating compressors routed to flares . You must calculate and report emissions from all reciprocating compressor sources that are routed to a flare as specified in paragraphs (p )(12)(i) through (p)(12)(iii) of this section.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 88 of 227
( i ) Paragraphs (p)(1) through (p)(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 flare, calculate the emissions for the f lare stack as specified in paragraph (n) of this section and report emissions from the flare as specified
in § 98 .236(n), without subtracting emissions attributable to compressor sources from the flare. (iii) Report all applicable activity data for compressors with compressor sources routed to flares as specified in § 98 .236(p). (q) Leak detection and leaker emission factors

. (q) Equipment leak surveys

. You must use the methods described in § 98.234(a) t o conduct leak detection(s) of equipment leaks from all component types listed in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This paragraph (q) applies to component types in streams with gas content greater than 10 percent
CH 4 plus CO 2 by weight. Component types in streams with gas content less than or equal to 10 percent CH 4 plus CO 2 by weight are exempt from the requirements of this paragraph (q) and do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of this paragraph (q) and do not need to be reported. If For industry segments listed in § 98 .230(a)(3) through (a)(8), if equipment lea ks are detected for

sources component types listed in this paragraph (q), then you must calculate equipment leak emissions per component type per reporting facility using Equations Equation W

- 30A or W

30B 30 of this section for each component type. Use Equati on W

- 30A for . For the industry segments segment listed in § 98 .230(a)( 3)

- (a)(7). Use 8), the results from Equation W

- 30B for industry segments listed in 98.230(a)(8). 30 are used to calculate population emission factors on a meter/regulator run basis using Eq uation W

- 31 of this section. If you chose to conduct equipment leak surveys at all above grade transmission

- distribution transfer stations over

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 89 of 227 multiple years, “n,” according to paragraph (q)(8)(i) of this section , then you must calculate the emissions fro m all above grade transmission

- distribution transfer stations as specified in paragraph (q)(9) of this section. 

# ( ) ∑

= 

### = x

p p i i s 

### T EF GHG E 1 , 

### * * 

# ∑

= 

### = p x

z z p p s i i p s 

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

### * * (Eq. W

- 30A 30 ) 

# ( ) ∑ ∑

+

− = = 

### = t

n t q x

p q p i i s 

### T EF GHG E 1 1 , , 

### * * (Eq. W

- 30B)

Where:

E s, p, i = Annual total volumetric GHG emissions at standard conditions of GHG i from each specific component type “p” (listed in § 98 .232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1)) in standard (“s”) cubic feet, as specified in paragraphs (q)(1) through (q)(8) of this section.

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

. EF EF s,p = Leaker emission factor for specific component types listed in Table W

- 2 through Table W

- 7 of this subpart. GHG i = For onshore natural gas processing f acilities, concentration of GHG i , CH 4 or CO 2 , in the total hydrocarbon of the feed natural gas; for onshore natural gas transmission compression and underground natural gas storage, GHG i equals 0.975 for CH 4 and 1.1 ×10 − 2 for CO 2 ; for LNG storage and LNG import and export equipment, GHG i equals 1 for CH 4 and 0 for CO 2 ; and for natural gas distribution, GHG i equals 1 for CH 4 and 1.1 × 10 − 2 CO 2 . T p ,z = The total time the surveyed component , “z”, component type “ p , ”, was found assumed to be leaking and operational, in hours. If one leak detection survey is conducted in the calendar year , assume the component was leaking for the entire calendar year

. , accounting for time the component was not operational ( i.e. , not operating under pressure) using 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 be leaking has been leaking since the previous survey (if not found leaking in the previous survey) or the beginning of the calendar year (if it was found leaking in the previous survey ). ), accounting for time the component was not operational using engineering estimate based on best available data. For the last leak detection survey in the calendar year, assum e that all leaking components continue to leak until the end of the calendar year , accounting for time the This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 90 of 227 component was not operational using engineering estimate based on best available data

. t = Calendar year of reporting.

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

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

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

- 30B should be for years that the data i s available. T p,q = The total time the component, p, was found leaking and operational, in hours, in year q. If one leak detection survey is conducted, assume the component was leaking for the entire period n. If multiple leak detection surveys are conduct ed, assume that the component found to be leaking has been leaking since the previous survey (if not found to be leaking in the previous survey) or the beginning of the calendar year (if it was found to be leaking in the previous survey). For the last leak detection survey in the cycle, assume that all leaking components continue to leak until the end of the cycle. (1) You must select to conduct either one leak detection survey in a calendar year or multiple complete leak detection surveys in a calendar yea r. The number of leak detection surveys selected must be conducted during the calendar year. (2) Calculate GHG both CO 2 and CH 4 mass emissions in carbon dioxide equivalent at standard conditions using calculations in paragraph (v) of this section. (3) Onshore natural gas processing facilities shall must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non

compressor components in gas service listed in Table W

- 2 of this subpart for equi pment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters

. (4) Onshore natural gas transmission compression facilities shall must use the appropriate default total hydrocarbon leaker emission factors for compressor c omponents in gas service and

non - compressor components in gas service listed in Table W

- 3 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters

. (5) Underground natural gas storage facili ties for storage stations shall must use the appropriate default total hydrocarbon leaker emission factors for storage stations in gas service This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 91 of 227

listed in Table W

- 4 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressu re relief valves, and meters

. (6) LNG storage facilities shall must use the appropriate default methane leaker emission factors for LNG storage components in gas service listed in Table W

- 5 of this subpart for equipment leaks detected from valves, pump seal s, connectors, and other

. (7) LNG import and export facilities shall must use the appropriate default methane leaker emission factors for LNG terminals components in LNG service listed in Table W

- 6 of this subpart for equipment leaks detected from valves, p ump seals, connectors, and other

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

- distribution transfer stations, shall must use Equation W

- 30 of this section and the appropriate default methane leaker emission factors for transmission

- distribution transfer station components in gas service listed in Table W

- 7 of this subpart for equipment leaks detected from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open ended lines. Leak detection at natural to calculate component emissions from annual equipment leak surveys conducted at above grade transmission

- distribution transfer stations. Natural gas distribution facilities is only are required to perform equipment leak surveys only at above gra de stations that qualify as transmission

- distribution transfer stations. Below grade transmission

- distribution transfer stations and all metering

- regulating stations that do not meet the definition of transmission

distribution transfer stations are not req uired to perform component equipment leak detection surveys under this section. (i) Natural gas distribution facilities may choose to conduct equipment leak detection surveys at the T

- D all above grade transmission

- distribution transfer stations over multiple years , “n” , not exceeding a five year period to cover all T

- D above grade transmission

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 92 of 227

distribution transfer stations. If the facility chooses to use the multiple year option , then the number of T

- D transmission

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

. (ii) [Reserved] (ii) Use Equation W

- 31 of this section to determine th e meter/regulator run population emission factors for each GHG i . As additional survey data become available, you must recalculate the meter/regulator run population emission factors for each GHG i annually according to paragraph (q)(8)(iii) of this section.



## ∑ ∑ ∑ ∑

= = = = = n

y Count

w y w n

y p y i p s
i MR s y MR

T E EF

1 1 , 1 7

1 , , ,

, , , (Eq. W

- 31)

Where:

EF s,MR,i = Meter/regulator run population emission factor for GHG i based on all surveyed above grade transmission

- distribution transfer stations over “n” years, in standard cubic feet of GHG i per operational hour of all meter/regulator runs. E s,p,i,y = Annual total volumetric emissions at standard conditions of GHG i from component type “p” during year “y” in standard (“s”) cubic feet, as calculated using Equation W

- 30 of this section. p = Seve n component types listed in Table W

- 7 of this subpart for transmission

distribution 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 based on best avai lable data. Count MR,y = Count of meter/regulator runs surveyed at above grade transmission

distribution 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. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 93 of 227

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 transmission

- distribution transfer stations over multiple y ears, “n,” according to paragraph (q)(8)(i) of this section and you have submitted a smaller number of annual reports than the duration of the selected cycle period of 5 years or less, then all available data from the current year and previous years must b e used in the calculation of the emission factor “EF s,MR,i ” from Equation W

- 31 of this section

. After the first survey cycle of “n” years is completed and beginning 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 years , such that each annual calculation of the emission factor “EF s,MR,i ” from Equation W

- 31 of this section is based on survey results from “n” years. Upon co mpletion of a cycle , you may elect to change the number of years in the next 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 “EF 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 t he survey results from the preceding number years that is equal 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 years in the previous cycle, “n”, calculate “EF 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 survey results from all previ ous (n new - 1) calendar years

.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 94 of 227
(9) If you chose to conduct equipment leak surveys at all above grade transmission

distribution transfer stations over multiple years, “n,” according to paragraph (q)(8)(i) of this section , you must use t he meter/regulator run population emission factors calculated using Equation W

- 31 of this section and the total count of all meter/regulator runs at above grade transmission

- distribution transfer stations to calculate emissions from all above grade transmission

- distribution tran sfer stations using Equation W

- 32B in paragraph (r) of this section

. (r) Population count and emission factors

. (r) Equipment leaks by population count

. This paragraph applies to emissions sources listed in § 98.232 (c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on streams 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 10 percent CH 4 plus CO 2 by weight are exempt from the requirements of this p aragraph ( r ) and do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of paragraph (r) of this section and do not need to be reported. Calculate You must calculate emissions from all emissi on sources listed in this paragraph using Equation W

- 31 32A of this section

. , except for natural gas distribution facility emission sources listed in § 98 .232(i)(3 ). Natural gas distribution facility emission sources listed in § 98 .232(i)(3) must calculate emissions using Equation W

- 32B and according to paragraph (r)(6) (ii) of this section.

s i s s i s T GHG EF Count E * * *

, = e i e s e i e s T GHG EF Count E * * *

, , , = (Eq. W

- 31 32A )

avg w i MR s MR i MR s T EF Count E

, , , , , * * = (Eq. W

- 32B)

Where:

E s, e, i = Annual volumetric GHG emissions at of GHG i from the emission source type in standard conditions from each component type in cubic feet. The emission source type may be a component ( e.g. connector, open

- ended line, etc.),
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 95 of 227 below grade metering

- regulating station, below grade transmission

distributio n transfer station, distribution main, or distribution service. E s,MR,i = Annual volumetric emissions of GHG i from all meter/regulator runs at above grade metering regulating stations that are not above grade transmission

distribution transfer stations or, when used to calculate emissions according to paragraph (q)(9) of this section, the a nnual volumetric emissions of GHG i from all meter/regulator runs at above grade transmission

- distribution transfer station s , in standard cubic feet. Count s Count e = To tal number of this type of the emission source type at the facility. For onshore petroleum and natural gas production facilities , average component counts are provided by major equipment piece in Tables W

- 1B and Table W

1C of this subpart. Use average compo nent counts as appropriate for operations in Eastern and Western U.S., according to Table W

- 1D of this subpart. Underground natural gas storage shall facilities must count the components each component listed for population emission factors in Table W

- 4

. LNG Storage shall of this subpart. LNG storage facilities must count the number of vapor recovery compressors. LNG import and export shall facilities must count the number of vapor recovery compressors. Natural gas distribution shall facilities must count the m eter/regulator runs : (1) the number of distribution services by material type; (2) miles of distribution mains by material type; and (3) number of below grade metering

- regulating stations, by pressure type; as described listed in paragraph (r)(6) Table W

- 7 of this section subpart

. Count MR = Total number of meter/regulator runs at above grade metering

- regulating stations that are not above grade transmission

- distribution transfer stations or, when used to calculate emissions according to paragraph (q)(9) of t his section, the total number of meter/regulator runs at above grade transmission

distribution transfer stations. EF EF s,e = Population emission factor for the specific component emission source type, as listed in Table W

- 1A and Tables W

- 3 1A and W

- 4 through Table W

- 7 of this subpart. Use appropriate population emission factor for operations in Eastern and Western U.S., according to Table W

- 1D of this subpart. EF for meter/regulator runs at above grade metering

- regulating stations is determined in Equation W

- 3 2 of this section. EF s,MR,i = Meter/regulator run population emission factor for GHG i based on all surveyed above grade transmission

- distribution transfer stations over “n” years, in standard cubic feet of GHG i per operational hour of all meter/regulator r uns, as determined in Equation W

- 31. GHG i = For onshore petroleum and natural gas production facilities, concentration of GHG i , CH 4 , or CO 2 , in produced natural gas as defined in paragraph (u)(2) of this section; for onshore natural gas transmission compression and underground natural gas storage, GHG i equals 0.975 for CH 4 and 1.1 × 10 − 2 for CO 2 ; for LNG storage and LNG import and export equi pment, GHG i This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 96 of 227 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 2 CO 2 . T s T e = Average estimated time that each component emission source type associated with the equipment leak emission was operational in the calendar year, in hours, using engineering estimate based on best available data. T w,avg = Average estimated time that each meter/regulator run was operational in the calendar year, i n hours per meter/regulator run, using engineering estimate based on best available data. (1) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (2) Onshore petroleum and natural gas pro duction facilities shall must use the appropriate default whole gas population emission factors listed in Table W

- 1A of this subpart for equipment leaks from valves, connectors, open ended lines, pressure relief valves, pump, flanges, and other

. Major equip ment and components associated with gas wells are considered gas service components in reference to Table W

- 1A of this subpart and major natural gas equipment in reference to Table W

- 1B of this subpart. Major equipment and components associated with crude oil wells are considered crude service components in reference to Table W

- 1A of this subpart and major crude oil equipment in reference to Table W

- 1C of this subpart. Where facilities conduct EOR operations the emissions factor listed in Table W

- 1A of this subpart shall be used to estimate all streams of gases, including recycle CO 2 stream. The component count can be determined using either of the methodologies calculation methods described in this paragraph (r)(2). The same methodology calculation method mus t be used for the entire calendar year. (i) Component Count Method ology Method 1

. For all onshore petroleum and natural gas production 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.
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 97 of 227 (B) Multiply major equipment counts by the average component counts listed in Table
W

- 1B and W

- 1C of this subpart for onshore natural gas production and onshore oil production,

re spectively. Use the appropriate factor in Table W

- 1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W

- 1D of this subpart. (ii) Component Count Method ology Method 2

. Count each component individually for the faci lity. Use the appropriate factor in Table W

- 1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W

- 1D of this subpart. (3) Underground natural gas storage facilities for storage wellheads shall must use the
appropr iate default total hydrocarbon population emission factors for storage wellheads in gas service listed in Table W

- 4 of this subpart for equipment leak from connectors, valves, pressure relief valves, and open ended lines

. (4) LNG storage facilities shall must use the appropriate default methane population emission factors factor for LNG storage compressors in gas service listed in Table W

- 5 of this subpart for equipment leak from vapor recovery compressors

. (5) LNG import and export facilities shall must use the appropriate default methane population emission factor for LNG terminal compressors in gas service listed in Table W

- 6 of this subpart for equipment leak from vapor recovery compressors

. (6) Natural gas distribution facilities shall must use the approp riate methane emission factors as described in paragraph paragraph s (r)(6 ) ) (i) and (r)(6)(ii ) of this section. (i) Below grade metering

- regulating stations ; , distribution mains ; , and distribution services , shall must use the appropriate default methane pop ulation emission factors listed in Table W

- 7 of this subpart. Below grade T

- D transmission

- distribution transfer stations shall must use the emission factor for below grade metering

- regulating stations.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 98 of 227
(ii) Above grade metering

- regulating stations that are not above grade transmission

distribution transfer stations must use the meter/regulator run population emission factor calculated in Equation W

- 31. Natural gas distribution facilities that do not have above grade transmission

- distribution transfer station s are not required to calculate emissions for above grade metering

- regulating stations and are not required to report GHG emissions in § 98.23 6 ( r )( 2)(v)

. Emissions from all above grade metering

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

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

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

- 31. The facility wide em ission factor in Equation W

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

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

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

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

regulating stations only and do not have to comply with §98.236(c)(16)(xix).

Count E EF i s 8760

, ÷
= (Eq. W

- 32)

Where:

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

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

- 30B.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 99 of 227

Count = Total number of meter/regulator runs at all TD transfer stations that were monitored over the years that constitute one complete cycle as per (q)(8)(i) of this section. 8760 = Conversion to hourly emissions (s) Offshore petroleum and natural gas production facilities

. Report CO 2, CH 4 , and N 2 O emissions for offshore petroleum and natural gas production from all equipment leaks, vented emission, and flare emission source types as identified in the data collection a nd emissions estimation study conducted by BOEMRE in compliance with 30 CFR 250.302 through 304. (1) Offshore production facilities under BOEMRE jurisdiction shall report the same annual emissions as calculated and reported by BOEMRE in data collection and emissions estimation study published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). (i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication year, report the most recent BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). Adjust emissions based on the operating time for the facility relative to the operating time in the most recent BOEMRE published study. (ii) [Reserved] (2) Offshore production faci lities that are not under BOEMRE jurisdiction shall must use the most recent monitoring methods and calculation m ethod ologie s m ethods published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report annual emissions (GOADS). (i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication, you may report the most recent recently reported emissions data submitted to demonstrate compliance with this subpart of part 98, with emissions adjuste d based on the operating time for the facility relative to operating time in the previous reporting period. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 100 of 227
(ii) [Reserved] (3) If BOEMRE discontinues or delays their data collection effort by more than 4 years, then offshore reporters shall once in every 4 years use the most recent BOEMRE data collection and emissions estimation methods to report estimate emissions. These emission estimates would be used to report emissions from the facility sources as required in paragraph (s) (1)(i) of this section

. (4) F or 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 shall must use the most recent BOEMRE data collection and emissions estimati on methods published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS) to report emissions

. . (t) Volumetric GHG volumetric emissions using actual conditions

. If equation parameters in § 98.233 are already determined at standard conditions as provided in the introductory text in § 98.233 , which results in volumetric emissions at standard conditions, then this paragraph does not apply. Calculate volumetric emissions at standard conditions as specified in para graphs (t)(1) or (2) of this section, with actual pressure and temperature determined by engineering estimates based on best available data unless otherwise specified. (1) Calculate natural gas volumetric emissions at standard conditions using actual natur al 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). 

## ( ) ( )
s a a s n a n s P T P T E E * 67

. 459 * 67

. 459 *

,

, + +
= 

## ( ) ( )
a s a a s n a n s Z P T P T E E * * 67

. 459 * 67

. 459 *

,

, + +

= (Eq. W

- 33)

Where:
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 101 of 227

E s,n = Natural gas volumetric emissions at standard temperature 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 under 98.233(g). E a,n = Natural gas volumetric emissions at a ctual conditions in cubic feet, except E a,n equals FR a,p for each well p when calculating either subsonic or sonic flowrates under 98.233(g). T s = Temperature at standard conditions (60 °F). T a = Temperature at actual emission conditions (°F). P s = Absolut e pressure at standard conditions (14.7 psia). P a = Absolute pressure at actual conditions (psia). Z a = Compressibility factor at actual conditions for natural gas. You may use either a default compressibility factor of 1, or a site

- specific compressibility factor based on actual temperature and pressure conditions. (2) Calculate GHG volumetric emissions at standard conditions using actual GHG emissions temperature and pressure, and Equation W

- 34 of this section. 

## ( ) ( )
s a a s i a i s P T P T E E * 67

. 459 * 67

. 459 *

,

, + +

= 

## ( ) ( )
a s a a s i a i s Z P T P T E E * * 67

. 459 * 67

. 459 *

,

, + +

= (Eq. W

- 34)

Where:

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

. T a = Temperature at actual emission conditions (°F). P s = Absolute pressure at standard conditions (14.7 psia). P a = Absolute pressure at actual conditions (psia). Z a = Compressibility factor at actual conditions for GHG i. You may use either a default compressibility factor of 1, or a site

- specific 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 emissi ons from 68 °F to 60 °F. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 102 of 227
(u) GHG volumetric emissions

. at standard conditions

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

. (1) Estimate CH 4 and CO 2 emissions from natural gas emissions using Equation W

- 35 of this section.
(Eq. W

- 35)
Where:

E s,i = GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions in cubic feet. E s,n = Natural gas volumetric emissions at standard conditions in cubic feet. M i = Mole fraction of GHG i in the natural gas. (2) For Equation W

- 35 of this section, the mole fraction, M i , shall be the annual average mole fraction for each sub

- basin category or facility, as specified in paragraphs (u)(2)(i) through (vii) of this section. (i) GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities . If you have a continuous gas composition analyzer for produced natural gas, you must use an annual average of these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then you must use an annual average gas

com position based on your most recent available analysis of the sub

- basin category or facility, as applicable to the emission source. (ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the de

methanizer or dew point control and G HG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de

- methanizer i n s i s M E E *

, , =

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 103 of 227 overhead or dew point control for onshore natural gas processing facilities . For onshore natural gas processing pla nts that solely fractionate a liquid stream, use the GHG mole percent in feed natural gas liquid for all streams. If you have a continuous gas composition analyzer on feed natural gas, you must use these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then annual samples must be taken according to methods set forth in § 98.234(b). (iii) GHG mole fraction in transmission pipeline natural gas that passes through the facility for the onshore natural gas trans mission compression industry segment

. You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data

. (iv) GHG mole fraction in natural gas stored in the underground natural gas storage industry segment . You may use 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 avai lable 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 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering 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 from transmission pipelines, you may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available da ta

. (vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities . You may use either a default 95 percent methane

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 104 of 227 and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data

. (v) GHG mass emissions

. Calculate GHG mass emissions in carbon dioxide equivalent metric tons by converting the GHG volumetric emissions at standard conditions into mass emissi ons using Equation W

- 36 of this section.

3

, 10 * * * − = GWP

E Mass i i s i ρ 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 CO 2 e . E s,i = GHG i (either CH 4 , CO 2 , or N 2 O) volumetric emissions at standard conditions, in cubic feet. P i 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.
GWP = Global warming potential, 1 for CO 2, 2 5 for CH 4 , and 298 for N 2 O

. (w) EOR injection pump blowdown

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

- 37 of this section:

3 2 2 10 * * * * − = CO c v CO GHG R V N Mass (Eq. W

- 37)

Where:

Mass CO2 = Annual EOR injection gas venting pump system emissions in met ric tons from blowdowns. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 105 of 227

N = Number of blowdowns for the equipment EOR injection pump system in the calendar year. V v = Total volume in cubic feet of blowdown equipment EOR injection pump system chambers (including pipelines, manifolds and vessels) between isolation valves. R c = Density of critical phase EOR injection gas in kg/ft 3 . You may use an appropriate standard method published by a consensus

- based standards organization if such a method e xists 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 liqu ids dissolved CO 2 . Calculate CO 2 emissions downstream of the storage tank from dissolved CO 2 in hydrocarbon liquids produced through EOR operations as follows: (1) Determine the amount of CO 2 retained in hydrocarbon liquids after flashing in tankage at STP conditions. Annual samples of hydrocarbon liquids downstream of the storage tank must be taken according to methods set forth in § 98.234(b) to determine retention of CO 2 in hydrocarbon liquids immediately downstream of the storage tank. Use the annual an alysis for the calendar year. (2) Estimate emissions using Equation W

- 38 of this section.

2 

### * CO hl hl 

### Mass S V = (Eq. W

- 38)

Where:

Mass CO2 = Annual CO 2 emissions from CO 2 retained in hydrocarbon liquids produced through EOR operations beyond tankage, in metric tons. S hl = Amount of CO 2 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel, under standard conditions. V hl = Total volume of hydrocarbon liquids produced at the EOR operations in barrels in the calendar year.
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 106 of 227 (y) [Reserved] (z) Onshore petroleum and natural gas production and natural gas distribution combustion emissions

. Calculate CO 2, CH 4 , and N 2 O combustion

- related emissions from stationary or portable equipment, except as specified in paragraph (z)(3) and (z)(4) of this section, as follows: (1) If a fuel combusted in the stationary or portable equipment is listed in Table C

- 1 of subpart C of this part, or is a blend containing one or more fuels listed in Table C

- 1, calculate emissions according to para graph (z)(1)(i ). ) of this section

. If the fuel combusted is natural gas and is of pipeline quality specification and has a minimum high heat value of 950 Btu per standard cubic foot, use the calculation method ology method described in paragraph (z)(1)(i) of this section and you may use the emission factor provided for natural gas as listed in Table C

- 1. If the fuel is natural gas, and is not pipeline quality or has a high heat value of less than 950 Btu per standard cubic feet, calculate emissions according to paragraph (z)(2 ). ) of this section

. If the fuel is field gas, process vent gas, or a blend containing field gas or process vent gas, calculate emissions according to paragraph (z)(2 ). ) of this section

. (i) For fuels listed in Table C

- 1 or a blend contai ning one or more fuels listed in Table C

1, calculate CO 2 , CH 4 , and N 2 O emissions according to any Tier listed in subpart C of this part. You must follow all applicable calculation requirements for that tier listed in § 98 .33, any monitoring or QA/QC requirements listed for that tier in § 98 .34, any missing data procedures specified in § 98.35, and any recordkeeping requirements specified in § 98 .37. (ii) Emissions from fuel combusted in stationary or portable equipment at onshore natural gas and petroleum production facilities and at natural gas distribution facilities will be reported

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 107 of 227 according to the requirements specified in § 98 .236 ( c)(19 z ) and not according to the reporting requirements specified in subpart C of this p art. (2) For fuel combustion units that combust field gas, process vent gas, a blend containing field gas or process vent gas, or natural gas that is not of pipeline quality or that has a high heat value of less than 950 Btu per standard cubic feet, calcul ate combustion emissions as follows: (i) You may use company records to determine the volume of fuel combusted in the unit during the reporting year. (ii) If you have a continuous gas composition analyzer on fuel to the combustion unit, you must use these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to the unit. If you do not have a continuous gas composition analyzer on gas to the combustion unit, you must use the appropriate gas compositions for each
str eam of hydrocarbons going to the combustion unit as specified in the applicable paragraph in (u)(2) of this section. (iii) Calculate GHG volumetric emissions at actual conditions using Equations W

- 39A and W

- 39B of this section: 

## ∑

= + = 5

1 2 2 , * * * ) * ( j j j a CO a CO a R Y V Y V E η (E q. W

- 39A) 

## ( ) 4 4 , 

### * 1 * CH a CH a 

### Y V E 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 conditions. V a = Volume of gas sent to combustion unit in actual cubic feet, during the year. Y CO2 = Concentration Mole fraction of CO 2 constituent in gas sent to combustion unit.
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E a,CH4 = Contribution of annual CH 4 emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions. η = Fracti on of gas combusted for portable and stationary equipment determined using engineering estimation. For internal combustion devices, a default of 0.995 can be used. Y

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

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

- related CH 4 and CO 2 mass emi ssions from volumetric
CH 4 and CO 2 emissions using calculation in paragraph (v) of this section. (vi) Calculate N 2 O mass emissions using Equation W

- 40 of this section. 

## ( ) GWP EF HHV Fuel Mass O N × × × × × = − 3 2 10 1 

## ( ) EF HHV Fuel Mass O N × × × × = − 3 2 10 1 (Eq. W

- 40)

Where:

Mass N 2 O = Annual N 2 O emissions from the combustion of a particular type of fuel (metric tons CO 2 e ). Fuel = Mass Annual mass or volume of the fuel combusted (mass or volume per year, choose appropriately to be consistent with the units of HHV). HHV = Higher heating value of fuel , mmBtu/unit of fuel (in units consistent with the fuel quantity combusted)

. For the higher heating value for field gas or process vent gas, you may use either a default higher heating value of 1.235 × 10 − 3 mmBtu/scf for HHV or a site

- specific higher heating value

. For natural gas that is not of pi p eline quality or that has a high heat value less than 950 Btu per standard 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. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 109 of 227

GWP = Global warming potential, as listed in Table A

- 1 of subpart A of this part. (3) External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissions or include these e missions for threshold determination in § 98.231(a). You must report the type and number of each external fuel combustion unit. (4) Internal fuel combustion sources, not compressor

- drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr (or th e equivalent of 130 horsepower), do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the type and number of each internal fuel combustion unit. § 98.234 Monitoring and QA/QC requirements

. The GHG emissions data for petroleum and natural gas 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. (a) You must use any of the methods described as follows in this paragraph to conduct leak detection(s) of equipment leaks and through

- valve leakage from all source types listed in § 98 .233(k), (o), (p) and (q) that occur during a calendar year , except as provided in paragraph (a)(4) of this section

. (1) Optical gas imaging instrument

. Use an optical gas imaging instrument for equipment leak detection in accordance with 40 CFR part 60, subpart A, § 60.18 of the Alter native work practice for monitoring equipment leaks , § 60.18(i)(1)(i); § 60.18(i)(2)(i) except that the monitoring frequency shall be annual using the detection sensitivity level of 60 grams per hour as stated in 40 CFR Part 60, subpart A, Table 1: Detecti on Sensitivity Levels ; § 60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, and § 60.18(i)(2)(iv) and (v); § 60.18(i)(3);

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 110 of 227
§ 60.18(i)(4)(i) and (v); including the requirements for daily instrument checks and distances, and excluding requireme nts for video records. Any emissions detected by the optical gas imaging instrument is a leak unless screened with Method 21 (40 CFR part 60, appendix A

- 7) monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, you must operate the optical gas imaging instrument to image the source types required by this subpart in accordance with the instrument manufacturer ’ s operating parameters. Unless using methods in paragraph (a)(2) of this section, an optical gas imaging instrument must be used for all source types that are inaccessible and cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface. (2) Method 21

. Use the equipment leak detection methods in 40 CFR part 60, appendix
A

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

. Use an infrared laser beam illuminated instrument for equipment le ak detection. Any emissions detected by the infrared laser beam illuminated instrument is a leak unless screened with Method 21 monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, you must operate the infrared laser beam illu minated instrument to detect the source types required by this subpart in accordance with the instrument manufacturer ’ s operating parameters. (4) [Reserved]

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(5) Acoustic leak detection device

. Use the acoustic leak detection device to detect through

- valve leakage. When using the acoustic leak detection device to quantify the through

valve leakage, you must use the instrument manufacturer ’ s calculation methods to quantify the through

- valve leak. When using the acoustic leak detection device, if a leak of 3.1 scf per hour or greater is calculated, a leak is detected. In addition, you must operate the acoustic leak detection device to monitor the source valves required by this subpart in accordance with the instrument manufacturer ’ s operating parameters. Acoust ic stethoscope type devices designed to detect through valve leakage when put in contact with the valve body and that provide an audible leak signal but do not calculate a leak rate can be used to identify non

- leakers with subsequent measurement required t o calculate the rate if through

- valve leakage is identified. Leaks are reported if a leak rate of 3.1 scf per hour or greater is measured. (b) You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure quantit ies reported in § 98 .233 according to the procedures in § 98 .3(i) and the procedures in paragraph (b) of this section. You may use an appropriate standard method published by a consensus

- based standards organization if such a method exists or you may use

a n industry standard practice. Consensus

- based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanic al Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). (c) Use calibrated bags (also known as vent bags) only where the emissions are at near

atmospheric pressures and below the maximum temperatu re specified by the vent bag

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 112 of 227 manufacturer such that the bag is safe to handle. The bag opening must be of sufficient size that the entire emission can be tightly encompassed for measurement till the bag is completely filled. (1) Hold the bag in place enclo sing the emissions source 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 fil l the bag, report the emissions as the average of the three readings. (3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98 .233(t). (4) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in § 98 .233(u) and (v). (d) Use a high volume sampler to measure emissions within the capacity of the instrument. (1) A technician following manufacturer instructions shall conduct measurements, including equipment manufac turer operating procedures and measurement method ologie s methods relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creating backpressure on the

source. (2) If the high volume sampler, along with all attachments available from the manufacturer, is not able to capture all the emissions from the source then use anti

- static wraps or other aids to capture all emissions without violating operating requirements as provided in the inst rument manufacturer ’ s manual.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 113 of 227 (3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98 .233(t). Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in § 98 .23 3(u) and (v). (4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent
CH 4 by using calibrated gas samples and by following manufacturer ’ s instructions for calibration. (e) Peng Robinson Equation of State means the equation of state defined by Equation W

41 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

. 0

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.
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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 . Fr om January 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 feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2015 as specified in paragraphs (f)(2) and (f)(3) of this section. Starting no later than April 1, 2015, 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 (f)(4) of this section. Best available monitoring methods means any of the following methods: (i) Monitoring methods curre ntly used by the facility 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

- related measurement data

. You may use best available monitoring methods for well

- related measurement data identified in paragraphs (f)(2)(i) and (f)(2)(ii) of this section that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart. (i) If Calculation Metho d 1 for liquids unloading in § 98.233(f)(1) was used in calendar year 2014 and will be used again in calendar year 2015, the vented natural gas flow rate for any This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 115 of 227 well in a unique tubing diameter group and pressure group combination that has not been previo usly measured. (ii) If using Equation W

- 10A of this subpart to determine 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 pressur es 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 (f)(3)(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 compress or as found measurements of manifolded emissions from groups of centrifugal compressor sources according to § 98.233(o)(4) and (o)(5), in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage,
LNG sto rage, and LNG import and export equipment as specified in § 98 .232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2). (ii) Reciprocating compressor as found measurements of manifolded emissions from groups of reciprocating compressor sources according to § 98.233( p)(4) and (p)(5), in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in § 98 .232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1). ( 4 ) Re quests for extension of the use of best available monitoring methods beyond March 31, 2015. You may submit a request to the Administrator to use one or more best available

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 116 of 227 monitoring methods for sources listed in paragraphs (f)(2) and (f)(3) of this section beyond March 31, 2015. (i) Timing of request

. The extension request must be 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 paramete rs 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 that 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 date by which the equipment will be installed and operating. (iii) Approval criteri a . T o obtain approval to use best available monitoring methods after March 31, 2015 , you must submit a request demonstrating to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitor ing equipment by April 1, 2015. The use of best available methods under paragraph (f) of this section will not be approved beyond December 31, 2015. (f) Special reporting provisions

— (1) Best available monitoring methods

. EPA will allow owners or operators to use best available monitoring methods for parameters in § 98.233 Calculating GHG Emissions as specified in paragraphs (f)(2), (f)(3), and (f)(4) of this section. If the reporter anticipates the potential need for best available monitoring for sources for which they need to petition EPA and the situation is unresolved at the time of the deadline, reporters

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 117 of 227 should submit written notice of this potential situation to EPA by the specified deadline for requests to be consid ered. EPA reserves the right to review best available monitoring method requests submitted after the deadlines specified in this section, and will consider requests which demonstrate unique or unusual circumstances unforeseen at the time of the applicable best available monitoring method deadline. The Administrator reserves the right to request further information in regard to all petition requests. The owner or operator must use the calculation methodologies and equations in § 98.233 Calculating GHG Emissi ons. Best available monitoring methods means any of the following methods specified in paragraph (f)(1) of this section: (i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart. (ii) Supplier data. (iii) En gineering calculations. (iv) Other company records. (2) Best available monitoring methods for well

- related emissions

. During January 1, 2011 through December 31, 2011, owners and operators may use best available monitoring methods for any well

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

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

. During January 1, 2011 through December 31, 2011, owners or operators may use best available monitoring methods for

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 118 of 227 activity dat a as listed below that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart. These sources are: (i) Cumulative hours of venting, days, or times of operation in § 98.233(e), (f), (g), (h), (l), (o), (p), (q), and (r). (ii) Number of blowdowns, completions, workovers, or other events in § 98.233(f), (g), (h), (i), and (w). (iii) Cumulative volume produced, volume input or output, or volume of fuel used in paragraphs § 98.233(d), (e), (j), (k), (l), (m), (n), (x), (y ), and (z). (4) Best available monitoring methods for leak detection and measurement

. During January 1, 2011 through December 31, 2011, owners or operators may use best available monitoring methods for sources requiring leak detection and/or measurement th at cannot reasonably be obtained according to the monitoring and QA/QC requirements of this part. These sources include: (i) Reciprocating compressor rod packing venting in onshore natural gas processing, onshore natural gas transmission compression, under ground natural gas storage, LNG storage, and LNG import and export equipment as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1). (ii) Centrifugal compressor wet seal oil degassing venting in onshore natural gas processing, onshore natural g as transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2). (iii) Acid gas removal vent stacks in onshore petroleum and natural gas produ ction and onshore natural gas processing as specified in § 98.232(c)(17) and (d)(6).

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 119 of 227 (iv) Equipment leak emissions from valves, connectors, open ended lines, pressure relief valves, block valves, control valves, compressor blowdown valves, orifice meters, other meters, regulators, vapor recovery compressors, centrifugal compressor dry seals, and/or other equipment leaks in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import a nd export equipment, and natural gas distribution as specified in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). (v) Condensate (oil and/or water) storage tanks in onshore natural gas transmission compression as specified in § 98.232(e)(3). (5 ) Requests for the use of best available monitoring methods

. (i) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for the sources specified in paragraph (f)(2) of this section. (ii) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for sources specified in paragraph (f)(3) of this section. (iii) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for sources specified in paragraph (f)(4) of this section. (iv) No request or approval by the Administrator is necessary to use best avai lable monitoring methods for data that cannot reasonably be obtained between January 1, 2011 and December 31, 2011 for sources not listed in paragraph (f)(2), (f)(3), and (f)(4) of this section. (6)

- (7) [Reserved]

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(8) Requests for extension of the use of b est available monitoring methods beyond 2011 for sources listed in paragraphs (f)(2), (f)(3), (f)(4), and (f)(5)(iv) of this section

— (i) Timing of request

. EPA does not anticipate a need for best available monitoring methods beyond 2011, but for all report ing years after 2011, best available monitoring methods will be considered for unique or unusual circumstances which include data collection methods that do not meet safety regulations, technical infeasibility, or counter to other local, State, or Federal regulations. For use of best available monitoring methods in 2012, an initial notice of intent to request best available monitoring methods must be submitted by December 31, 2011. Any notice of intent submitted prior to the effective date of this rule cann ot be used to meet this December 31, 2011 deadline; a new notice of intent must be signed and submitted by the designated representative. In addition to the initial notification of intent, owners or operators must also submit an extension request containin g the information specified in 98.234(f)(8)(ii) by March 30, 2012. Any best available monitoring methods request submitted prior to the effective date of this rule cannot be used to meet the March 30, 2012 deadline; a new best available monitoring methods request must be signed and submitted by the designated representative. Owners or operators that submit both a timely notice of intent and extension request consistent with 98.234(f)(8)(ii) can automatically use best available monitoring method through June 30, 2012, for the specific parameters identified in their notification of intent and best available monitoring methods request regardless of whether the best available monitoring methods request is ultimately approved. Owners or operators that submit a no tice of intent but do not follow up with a best available monitoring methods request by March 30, 2012 cannot use best available monitoring methods in 2012. For 2012, when an owner or operator has submitted a notice of intent and a subsequent best availabl e monitoring method extension request, use of best available monitoring methods will be valid,

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

. To obtain approval to use best available monitoring methods after December 31, 2011, the owner or operator must submit a request demonstrating to the Administrator's satisfaction that the owner or operator faces unique or unusual circumstances which i nclude, by way of example and not in limitation, clearly demonstrated data collection methods that do not meet safety regulations, technical infeasibility, or counter to other local, State, or Federal regulations, along with the reasons the owner or operat or cannot otherwise address the unique or unusual circumstances as required to be demonstrated in this paragraph. (f) Special reporting provisions

— ( 1) Best available monitoring methods

. EPA will allow owners or operators to use best available monitoring methods for parameters in § 98 .233

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 122 of 227 Calculating GHG Emissions as specified in paragraphs (f)(2 ), (f)( 3 ), and (f)( 4 ) of this section. If the reporter anticipates the potential need for best available monitoring for sources for which they need to petition EPA and the situation is unresolved at the time of the deadline, reporters should submit written notice of this potential situation to EPA by the specified deadline for requests to be considered. EPA reserves the right to review best available monitoring meth od requests submitted after the deadlines specified in this section, and will consider requests which demonstrate unique or unusual circumstances unforeseen at the time of the applicable best available monitoring method deadline. The Administrator reserves the right to request further information in regard to all petition requests. The owner or operator must use the calculation methodologies and equations in § 98.233 Calculating GHG Emissions. Best available monitoring methods means any of the following met hods specified in paragraph (f)(1) of this section : (i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart. (ii) Supplier data. (iii) Engineering calculations. (iv) Other company records. (2) Best available monitoring methods for well

- related emissions

. During January 1, 2011 through December 31, 2011, owners and operators may use best available monitoring methods for any well

- related data that cannot reasonably be measured according to the mon itoring and QA/QC requirements of this subpart

. These well

- related sources are: (i) Gas well venting during well completions and workovers with hydraulic fracturing as specified in § 98 .233(g ). (ii) Well testing venting and flaring as specified in § 98.233 (l).

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(3) Best available monitoring methods for specified activity data

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

. During January 1, 2011 through December 31, 2011, owners or operators may use best available monitoring methods for sources requiring leak detection and/or me asurement that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this part. These sources include: (i) Reciprocating compressor rod packing venting in onshore natural gas processing, onshore natural gas transmission compre ssion, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in § 98 .232(d)( 1 ), (e)( 1 ), (f)( 1 ), (g)( 1), and ( h)(1). (ii) Centrifugal compressor wet seal oil degassing venting in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in § 98 .232(d)( 2 ), (e)( 2 ), (f)( 2 ), (g)( 2 ), and (h)( 2 ).

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( iii) Acid gas removal ve nt stacks in onshore petroleum and natural gas production and onshore natural gas processing as specified in § 98.232(c)(17) and (d)(6). (iv) Equipment leak emissions from valves, connectors, open ended lines, pressure relief valves, block valves, control valves, compressor blowdown valves, orifice meters, other meters, regulators, vapor recovery compressors, centrifugal compressor dry seals, and/or other equipment leaks in onshore natural gas processing, onshore natural gas transmission compression, underg round natural gas storage, LNG storage, LNG import and export equipment, and natural gas distribution as specified in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)( 4 ), and (i)(1). (v) Condensate (oil and/or water) storage tanks in onshore natural gas transmi ssion compression as specified in § 98.232(e)(3). (5) Requests for the use of best available monitoring methods

. (i) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for the sources specified in paragraph (f)(2) of this section. (ii) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for sources specified in paragraph (f) (3) of this section. (iii) No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and December 31, 2011 for sources specified in paragraph (f)(4) of this section. (iv) No request or approva l by the Administrator is necessary to use best available monitoring methods for data that cannot reasonably be obtained between January 1, 2011 and December 31, 2011 for sources not listed in paragraph (f)(2), (f)(3), and (f)(4) of this section.

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(6)

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

— (i) Timing of request

. EPA does not anticipate a need for best available monitoring methods beyond 2011, but for all reporting years after 2011, best available monitoring methods will be considered for unique or unusual circumstances which include data collection methods that d o not meet safety regulations, technical infeasibility, or counter to other local, State, or Federal regulations. For use of best available monitoring methods in 2012, an initial notice of intent to request best available monitoring methods must be submitt ed by December 31, 2011. Any notice of intent submitted prior to the effective date of this rule cannot be used to meet this December 31, 2011 deadline; a new notice of intent must be signed and submitted by the designated representative. In addition to th e initial notification of intent, owners or operators must also submit an extension request containing the information specified in 98.234(f)(8)(ii) by March 30, 2012. Any best available monitoring methods request submitted prior to the effective date of t his rule cannot be used to meet the March 30, 2012 deadline; a new best available monitoring methods request must be signed and submitted by the designated representative. Owners or operators that submit both a timely notice of intent and extension request consistent with 98.234(f)(8)(ii) can automatically use best available monitoring method through June 30, 2012, for the specific parameters identified in their notification of intent and best available monitoring methods request regardless of whether the b est available monitoring methods request is ultimately approved. Owners or operators that submit a notice of intent but do not follow up with a best available monitoring methods request by March 30, 2012 cannot use best available monitoring methods in 2012 . For 2012, when an owner or operator has submitted a notice of intent and a subsequent best available

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 126 of 227 monitoring method extension request, use of best available monitoring methods will be valid, upon approval by the Administrator, until the date indicated in the approval or until December 31, 2012, whichever is earlier. For reporting years after 2012, a new request to use best available monitoring methods must be submitted by June 30th of the year prior to the reporting year for which use of best available monitoring methods is sought

. (ii) Content of request

. Requests must contain the following information: (A) A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods. (B) For ea ch specific source for which an owner or operator is requesting use of best available monitoring methods, a description of the unique or unusual circumstances, such as data collection methods that do not meet safety regulations, technical infeasibility, or specific laws or regulations that are counter to data collection methods that conflict with each specific source

. (C) A detailed explanation and supporting documentation of how and when the owner or operator will comply with all of the subpart W reporting requirements for which use of best available monitoring methods are sought

. (iii) Approval criteria

. T o obtain approval to use best available monitoring methods after December 31, 2011, the owner or operator must submit a request demonstrating to the Administrator's satisfaction that the owner or operator faces unique or unusual circumstances which include, by way of example and not in limitation, clearly demonstrated data collection methods that do not meet safety regulations, technical infeasibility, or counter to other local, State, or Federal regulations, along with the reasons the owner or operator cannot otherwise address the unique or unusual circumstances as required to be demonstrated in this paragrap h.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 127 of 227 (g) For the purposes of fulfilling requirements in 40 CFR 98.233(f) and (g) which require measurements to be taken every other year beginning in the first year of data collection, reporters have the option of taking the first measurement in 2012 to sati sfy the requirements for the 2011

- 2012 data collection cycle. (h) [Reserved] (g) [Reserved] (h) For well venting for liquids unloading, if a monitoring period other than the full calendar year is used to determine the cumulative amount of time in hours of venting for each well (the term “T p ” in Equation W

- 7 A and W

- 7 B of § 98 .233) or the number of unloading events per well (the term “V p ” in Equation s W

- 8 and W

- 9 of § 98 .233) , then the monitoring period must begin before February 1 of the reporting year and must not end before December 1 of the reporting year. The end of one monitoring period must immediately precede the start of the next monitoring period for the next reporting year . All production days must be monitored and all venting accounted for. § 98.235 Procedures for estimating missing data. A complete record of all estimated and/or measured parameters used in the GHG emissions calculations is required. If data are lost or a n error occurs during annual emissions estimation or measurements Except as specified in § 98 .233, whenever a value of a parameter is unavailable for a GHG emission calculation required by this subpart (including, but not limited to, if a measuring device malfunctions during unit operation or activity data are not collected), you must follow the procedures specified in paragraphs (a) through ( i ) of this section, as applicable.

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( a ) For stationary and por table combustion sources that use the calculation methods of subpart C of this part, you must use the missing data procedures in subpart C of this part. ( b ) For each missing value of a parameter that should have been measured quarterly o r more frequently u sing equipment including, but not limited to, a continuous flow meter, composition analyzer, thermocouple, or pressure gauge, you must substitute the arithmetic average of the quality

- assured values of that parameter immediately preceding and immediately
f

ollowing the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality

- assured data are available prior to the missing data incident, you must use the first quality

- assured value obtained after the missing data period as the substitute data value. A value is quality

- assured according to the procedures specified in § 98.234. ( c ) For each missing value of a parameter that should 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 missing data are not discovered unti l after December 31 of the year in which data are collected, until valid data for reporting is are obtained. Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used for that subsequent year's emissions est imation. Where missing data procedures are used for the previous year, at least 30 days must separate emissions estimation or measurements for the previous year and emissions estimation or measurements for the current year of data collection. For missing d ata which are continuously monitored or measured, (for example flow meters), or for missing temperature or pressure data that are required under § 98.236, the reporter may use best available data for use in emissions determinations. The reporter must record and report the basis for the best available data in these cases.

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( d ) For each missing value of a parameter that should have been measured biannually (every two years), you must conduct the estimation or measurement activity for those sources as
soon as po ssible in the subsequent calendar year if the estimation or measurement was not made
in the appropriate year (first year of data collection and every two years thereafter) , until valid data for reporting are obtained. Data developed and/or collected in a s ubsequent calendar year to substitute for missing data cannot be used to alternate or postpone subsequent biannual emissions estimation s or measurements

. ( e ) For the first six months of required data collection, facilities that become newly subject to thi s subpart W may use best engineering estimates for any data that cannot reasonably be measured or obtained according to the requirements of this subpart. ( f

) For the first six months of required data collection, facilities that are currently subject
to this subpart W and that acquire new 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 acco rding to the requirements of this subpart. ( g ) Unless addressed in another paragraph of this section , f or each missing value of any activity data, you must substitute data value(s) using 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). ( h ) You must report information for all measured and substitute values of a parameter, and the procedures used to substitute an unavailable v alue of a parameter per the requirements in § 98 .236(bb). ( i ) You must follow recordkeeping requirements listed in § 98 .23 7 (f)

.
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§ 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 specified in this section. Reporters that use a flow or volume measurement system that corrects to standard conditions as provided in the introductory text in § 98.233 f or data elements that are otherwise required to be determined at actual conditions, report gas volumes at standard conditions 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) Report annual emissions in metric tons of CO 2 e for each GHG separately for each of the industry segments listed in paragraphs (a)(1) through (8) of this section. (1) Onshore petroleum and natural gas product ion. (2) Offshore petroleum and natural gas production. (3) Onshore natural gas processing. (4) Onshore natural gas transmission compression. (5) Underground natural gas storage. (6) LNG storage. (7) LNG import and export. (8) Natural gas distribution. (b) For offshore petroleum and natural gas production, report emissions of CH 4 , CO 2 , and
N 2 O as applicable to the source type (in metric tons CO 2 e per year at standard conditions) individually for all of the emissions source types listed in the most recent BOEMRE study. (c) Report the information listed in this paragraph for each applicable source type in metric tons of CO 2 e for each GHG. If a facility operates under more than one industry segment,

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 131 of 227 each piece of equipment should be reported under the unit's respective majority use segment. When a source type listed under this paragraph routes gas to flare, separately report the emissions that were vented directly to the atmosphere without flaring, and the emissions that resulted from flaring the gas. Both th e vented and flared emissions will be reported under the respective source type and not under the flare source type. (1) For natural gas pneumatic devices (refer to Equation W

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

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

- 3 and Equation W

- 4 of §98.233), report the following:

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 132 of 227 (i) Total throughput off the acid gas removal unit using a mete r or engineering estimate based on process knowledge or best available data in million cubic feet per year. (ii) For Calculation Methodology 1 and Calculation Methodology 2 of §98.233(d), annual average fraction of CO 2 content in the vent from the acid gas removal unit (refer to §98.233(d)(6)). (iii) For Calculation Methodology 3 of §98.233(d), annual average volume fraction of
CO 2 content of natural gas into and out of the acid gas removal unit (refer to §98.233(d)(7) and (d)(8)). (iv) Report the annual quantity of CO 2 , expressed in metric tons CO 2 e, that was recovered from the AGR unit and transferred outside the facility, under subpart PP of this part. (v) Report annual CO 2 emissions for the AGR unit, expressed in metric tons CO 2 e. (vi) For the onshore natural gas processing industry segment only, report a unique name or ID number for the AGR unit. (vii) An indication of which calculation methodology was used for the AGR. (4) For dehydrators, report the following: (i) For each Glycol dehydrator with a th roughput greater than or equal to 0.4 MMscfd (refer to §98.233(e)(1)), report the following: (A) Glycol dehydrator feed natural gas flow rate in MMscfd, determined by engineering estimate based on best available data. (B) Glycol dehydrator absorbent circul ation pump type. (C) Whether stripper gas is used in glycol dehydrator. (D) Whether a flash tank separator is used in glycol dehydrator. (E) Type of absorbent.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 133 of 227 (F) Total time the glycol dehydrator is operating in hours. (G) Temperature, in degrees Fahrenhe it and pressure, in psig, of the wet natural gas. (H) Concentration of CH 4 and CO 2 in wet natural gas. (I) What vent gas controls are used (refer to §98.233(e)(3) and (e)(4)). (J) For each glycol dehydrator, report annual CO 2 and CH 4 emissions that resulte d from venting gas directly to the atmosphere, expressed in metric tons CO 2 e for each gas. (K) For each glycol dehydrator, report annual CO 2 , CH 4 , and N 2 O emissions that resulted from flaring process gas from the dehydrator, expressed in metric tons CO 2 e f or each gas. (L) For the onshore natural gas processing industry segment only, report a unique name or ID number for glycol dehydrator. (ii) For all glycol dehydrators with a throughput less than 0.4 MMscfd (refer to §98.233, Equation W

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

- 6 of §98.233), report the following: (A) Count of desiccant dehydrators.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 134 of 227 (B) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons
CO 2 e for each gas, for all absorbent desiccant dehydrators combined. (5) For well venting for liquids unloading, report the following: (i) For Calculation Methodology 1 (refer to Equation W

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

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

- 8 and W

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

- basin catego ry: (A) Count of wells vented to the atmosphere for liquids unloading.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 135 of 227 (B) Count of plunger lifts. (C) Cumulative number of unloadings vented to the atmosphere. (D) Average internal casing diameter, in inches, for all wells, where applicable. (E) Report an nual CO 2 and CH 4 emissions, expressed in metric tons CO 2 e for each GHG
gas. (6) For well completions and workovers, report the following for each sub

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

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

- 10A and W

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

- 10A of §98.233, measured flow rate of backflow during well completion in standard cubic feet per hour. 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 rep orting of this data element, you must report by the date specified in §98.236(c)(20) the measured flow rate of backflow during well completion and the API Well Number(s) for the wells included in the
measurement. (C) Total count of workovers in calendar ye ar that flare gas or vent gas to the atmosphere. (D) When using Equation W

- 10A, measured flow rate of backflow during well workover in standard cubic feet per hour. 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

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 136 of 227 for the measurement. If you elect to delay reporting of this data element, you must report by the date specified in §98.236(c)(20) the flow rate of backflow during well workover and the API Well Number(s) for the well(s) included in the measurement. (E) When using Equation W

- 10A, total number of days of backflow from all wells during completions. You may delay the reporting of this data element if you indicate in the annual report th at wildcat wells and/or delineation wells are the only wells included in this number. If you elect to delay reporting of this data element, you must report by the date specified in §98.236(c)(20) the total number of days of backflow from all wells during c ompletions and the API Well Number(s) for the well(s) included in the number. (F) When using Equation W

- 10A, total number of days of backflow from all wells during workovers. You may delay the reporting of this data element if you indicate in the annual re port that wildcat wells and/or delineation wells are the only wells included in this number. If you elect to delay reporting of this data element, you must report by the date specified in §98.236(c)(20) the total number of days of backflow from all wells d uring workovers and the API Well Number(s) for the well(s) included in the number. (G) Report number of completions employing purposely designed equipment that separates natural gas from the backflow and the amount of natural gas, in standard cubic feet,

r ecovered using engineering estimate based on best available. (H) Report number of workovers employing purposely designed equipment that separates natural gas from the backflow and the amount of natural gas, in standard cubic feet, recovered using engineeri ng estimate based on best available data. (I) Annual CO 2 and CH 4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 e for each gas.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 137 of 227
(J) Annual CO 2 , CH 4 , and N 2 O emissions that resulted from flares, expressed in metric
tons CO 2 e for each gas. (ii) For gas well completions and workovers without hydraulic fracturing (refer to Equation W

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

- 14A and Equation
W

- 14B of §98.233), report the following: (i) For each unique physical volume that is blown down more than once during the calendar year, report the following: (A) Total number of blowdowns for each unique physical volume in the calendar year. (B) Annual CO 2 and CH 4 emissions, for each unique physical blowdown volume , expressed in metric tons CO 2 e for each gas. (C) A unique name or ID number for the unique physical volume. (ii) For all unique volumes that are blown down once during the calendar year, report the following:

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 138 of 227 (A) Total number of blowdowns for all unique p hysical volumes in the calendar year. (B) Annual CO 2 and CH 4 emissions from all unique physical volumes as an aggregate per facility, expressed in metric tons CO 2 e for each gas. (8) For gas emitted from produced oil sent to atmospheric tanks: (i) For wellh ead gas

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

- basin category, unless otherwise specified: (A) Number of wellhead separators sending oil to atmospheric tanks. (B) Estimated average separator temperature, in degrees Fahrenheit, and estimated average pressure, in psig. (C) Estimated average sales oil stabilized API gravity, in degrees. (D) Count of hydrocarbon tanks at well pads. (E) Bes t estimate of count of stock tanks not at well pads receiving your oil. (F) Total volume of oil from all wellhead separators sent to tank(s) in barrels per year. You may delay the reporting of this data element if you indicate in the annual report that onl y wildcat and delineation wells in the sub

- basin have wellhead separators. If you elect to delay reporting the this data element, you must report by the date specified in §98.236(c)(20) the total volume of oil from all wellhead separators sent to tank(s) a nd the API Well Number(s) for the well(s) included in this volume. (G) Count of tanks with emissions control measures, either vapor recovery system or flaring, for tanks at well pads. (H) Best estimate of count of stock tanks assumed to have emissions cont rol measures not at well pads, receiving your oil.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 139 of 227 (I) Range of concentrations of flash gas, CH 4 and CO 2 . (J) Annual CO 2 and CH 4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO 2 e for each gas, for all wellhead gas

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

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

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

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

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

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

- basin category: (A) Total volume of sales oil from all wells in barrels per year. You may delay the 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 greater than or equal to 10 barrels per day. If you elect to delay reporting of this data element, you must report by the date specified in §98.3236(c)(20) the total volume of sales oil from all wells and the API Well Number(s) for the well(s) included in this vo lume. (B) Total number of wells sending oil directly to tanks. (C) Total number of wells sending oil to separators off the well pads.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 140 of 227 (D) Sales oil API gravity range for wells in (c)(8)(ii)(B) and (c)(8)(ii)(C) of this section, in degrees. (E) Count of hyd rocarbon tanks on wellpads. (F) Count of hydrocarbon tanks, both on and off well pads assumed to have emissions control measures: either vapor recovery system or flaring of tank vapors. (G) Annual CO 2 and CH 4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO 2 e for each gas, at the sub

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

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

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

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

- 15 of §98.233, report the following: (A) Number of wellhead separators. (B) Number of wells without wellhead separators

. (C) Total volume of oil production in barrels per year. (D) Best estimate of fraction of production sent to tanks with assumed control measures: either vapor recovery system or flaring of tank vapors. (E) Count of hydrocarbon tanks on well pads.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 141 of 227
(F) Annual CO 2 and CH 4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO 2 e for each gas, at the sub

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

- basin level for Calculation Methodology 5 of §98.233(j). (H) Annual CO 2, CH 4, and N 2 O emissions that resulted from flaring gas, expressed in metric tons CO 2 e for each gas, at the sub

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

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

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

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 142 of 227
(10) For well tes ting venting and flaring (refer to Equation W

- 17A or W

- 17B of §98.233), report the following: (i) Number of wells tested per basin in calendar year. (ii) Average gas to oil ratio for each basin. (iii) Average number of days the well is tested in a basin. (iv) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons
CO 2 e for each gas, emissions from well testing venting. (v) Report annual CO 2, CH 4, and N 2 O emissions at the facility level, expressed in metric
tons CO 2 e for each gas, emissions from well testing flaring. (11) For associated natural gas venting and flaring (refer to Equation W

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

- 19, W

- 20, and W

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

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

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 143 of 2 27 (iv) Whether flare has a continuous gas an alyzer. (v) Flare combustion efficiency. (vi) Report uncombusted CH 4 emissions, in metric tons CO 2 e (refer to Equation W

- 19 of §98.233). (vii) Report uncombusted CO 2 emissions, in metric tons CO 2 e (refer to Equation W

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

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

- 22 through
W

- 24 of §98.233), report the following for each degassing vent: (A) Number of wet seals connected to the degassing vent. (B) Fraction of vent gas recovered for fuel or sales or flared. (C) Annual throughput in million scf, use an engineering calculation based on best available data. (D) Type of meters used for making measurements.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 144 of 227 (E) Reporter emission factor for wet seal oil degassing vents in cubic feet per hour (refer to Equation W

- 24 of §98.233). (F) Total time the compressor is operating in hours. (G) Report seal oil degassing vent emissions for compressors measured and for compressors not measured in metric tons of CO 2 e for each gas. (ii) For wet and dry seal centrifugal compressors in operating mode , (refer to Equations
W

- 22 through W

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

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

- 22 through W

- 24 of §98.233), report the following: (A) Total ti me in hours the compressor is in shutdown, depressurized mode. (B) Reporter emission factor for isolation valve emissions in shutdown, depressurized mode in cubic feet per hour (refer to Equation W

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

- 25 of §98.233), report the following:

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 145 of 227 (A) Count of compressors. (B) Report annual emissions in metric tons of CO 2 e for each gas (refer to Equation W

- 25 of §98.233) collectively. (14) For reciprocating compressors: (i) F or reciprocating compressors rod packing emissions with or without a vent in operating mode, report the following: (A) Annual throughput in million scf, use an engineering calculation based on best available data. (B) Total time in hours the reciprocating compressor is in operating mode. (C) Report rod packing emissions for compressors measured and for compressors not measured in metric tons of CO 2 e for each gas. (ii) For reciprocating compressors blowdown vents not manifold to rod packing vents, in operati ng and standby pressurized mode (refer to Equations W

- 26 through W

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

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

- 26 through W

- 28 of §98.233), report the following: (A) Total time the compressor is in not operating, depressurized mode.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 146 of 227 (B) Reporter emission factor for isolation valve emissions in not operating, depressurized mode in cubic feet per hour (refer to Equation W

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

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

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

- 2, W

- 3, W

- 4, W

- 5, W

- 6, and W

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

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

- 30A of §98.233), by component type.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 147 of 227 (ii) For equipment leaks calculated using populatio n counts and factors (refer to §98.233(r)), report the following: (A) For source categories §98.230(a)(5), (a)(6), and (a)(7), total count for each component type in Tables W

- 4, W

- 5, and W

- 6 of this subpart for which there is a population emission factor, listed by major heading and component type. (B) For onshore production (refer to §98.230 paragraph (a)(2)), total count for each type of major equipment in Table W

- 1B and Table W

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

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

- D transfer stations in the facility. (ii) Number of years ov er which all T

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

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

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

- regulating station s (this count will include above grade T

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

- regulating stations (this count will include below grade T

- D transfer stations) in the facility. (vii) [Reserved] (viii) Leak factor fo r meter/regulator run developed in Equation W

- 32 of §98.233. (ix) Number of miles of unprotected steel distribution mains. (x) Number of miles of protected steel distribution mains. (xi) Number of miles of plastic distribution mains.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 148 of 227
(xii) Number of miles of cast iron distribution mains. (xiii) Number of unprotected steel distribution services. (xiv) Number of protected steel distribution services. (xv) Number of plastic distribution services. (xvi) Number of copper distribution services. (xvii) Annual CO 2 and CH 4 emissions, in metric tons CO 2 e for each gas, from all above grade T

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

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

- regulating stations (including T

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

- regulating statio ns (including T

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

- 37 of §98.233), report the following: (i) Pump capacity, in barrels per day. (ii) Volume of critical phase gas between isolation valves. (iii) Number of blowdowns per year. (iv) Crit ical phase EOR injection gas density.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 149 of 227 (v) For each EOR pump, report annual CO 2 emissions, expressed in metric tons CO 2 e for each gas. (18) For EOR hydrocarbon liquids dissolved CO 2 for each sub

- basin category (refer to Equation W

- 38 of §98.233), report the following: (i) Volume of crude oil produced in barrels per year. (ii) Amount of CO 2 retained in hydrocarbon liquids in metric tons per barrel, under standard conditions. (iii) Rep ort annual CO 2 e missions at the sub

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

- drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr or 130 horsepower, by type of unit. (vi) Report annual CO 2 , CH 4 , and N 2 O emission s from internal combustion units greater than 1mmBtu/hr, expressed in metric tons CO 2 e for each gas, by type of unit.

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(vii) Cumulative volume of fuel combusted in internal combustion units with a rated heat capacity larger than 1 mmBtu/hr or 130 horsepower , by fuel type. (20) If you elect to delay reporting the information in paragraph (c)(6)(i)(B), (D), (E), (F), (c)(8)(i)(F), or (c)(8)(ii)(A) of this section, you must report the information required in that paragraph no later than the date specified in paragraphs (c)(20)(i) through (iii) of this section, as applicable. (i) March 31, 2016, for reporting year 2013. (ii) March 31, 2017, for reporting year 2014. (iii) The date 2 years following the date specified in §98.3(b) introductory text, for reporting year 2015 and thereafter. (d) Report annual throughput as determined by engineering estimate based on best available data for each industry segment listed in paragraphs (a)(1) through (a)(8) of this section. (e) For onshore petroleum and natural gas produc tion, report the best available estimate of API gravity, best available estimate of gas to oil ratio, and best available estimate of average low pressure separator pressure for each oil sub

- basin category. (a) The annual report must include the informati on specified in paragraphs (a)(1) through ( a) (8) of this section for each applicable industry segment. 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 (a)(8) of this section, and each applicable emission source listed in paragraphs (b) through (z) of this section. (1) Onshore petroleum and natural gas production . For the equipment/activities specified in paragraphs (a)(1)(i) through (a)(1)(xvii) of this section, report the information specified in the applicable paragraphs of this section.

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(i) Natural gas pneumatic devices . Report the information specified in paragraph (b) of this section. (ii) Natural gas driven pneumatic pumps . Report the information specified in paragraph (c) of this section. (iii) Acid gas removal units . Report the information specified in paragraph (d) of this section. (iv) Dehydrators . Report the information specified in paragraph (e) of this section. (v) Liquids unload ing . Report the information specified in paragraph (f) of this section. (vi) Completions and workovers with hydraulic fracturing . Report the information specified in paragraph (g) of this section. (vii) Completions and workovers without hydraulic fracturin g . 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 s ection. (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 information specified in paragraph (o) of this section. (xiii) Reciprocating compressors . Report the information specified in paragraph (p) of this section.

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(xiv) Equipment leaks by population count . Report the information specified in paragraph (r) of this section. (xv) EOR inje ction pumps . Report the information specified in paragraph (w) of this section. (xvi) EOR hydrocarbon liquids . Report the information 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 equipment/activities specified in paragraphs (a)(3)(i) through (a)(3)(vii) o f 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 information specified in paragraph (p) of this section.

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(vii) Equipment leak surveys . Report the information specified in paragraph (q) of this section. (4) Onshore nat ural gas transmission compression . For the equipment/activities specified in paragraphs (a)(4)(i) through (a)(4)(vii) of this section, report the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices . Report the information specified in paragraph (b) of this section. (ii) Blowdown vent stacks . Report the information specified in paragraph (i) of this section. (iii) Transmission storage tanks . Report the information 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 information specified in paragra ph (p) of this section. (vii) Equipment leak surveys . Report the information specified in paragraph (q) of this section. (5) Underground natural gas storage . For the equipment/activities specified in paragraphs (a)(5)(i) through (a)(5)(vi) of this section, report the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices . Report the information specified in paragraph (b) of this section.

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(ii) Flare stacks . Report the information specified in paragraph (n) of th is section. (iii) Centrifugal compressors . Report the information specified in paragraph (o) of this section. (iv) Reciprocating compressors . Report the information specified in paragraph (p) of this section. (v) Equipment leak surveys . Report the informat ion specified in paragraph (q) of this section. (vi) Equipment leaks by population count . Report the information specified in paragraph (r) of this section. (6) LNG storage . For the equipment/activities specified in paragraphs (a)(6)(i) through (a)(6)(v) of this section, report the information specified in the applicable paragraphs of this section. (i) Flare stacks . Report the information specified in paragraph (n) of this section. (ii) Centrifugal compressors . Report the information specified in paragraph (o) of this section. (iii) Reciprocating compressors . Report the information specified in paragraph (p) of this section. (iv) Equipment leak surveys . Report the information specified in paragraph (q) of this section. (v) Equipment leaks by popul ation count . Report the information specified in paragraph (r) of this section.

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(7) LNG import and export equipment . For the equipment/activities specified in paragraphs (a)(7)(i) through (a)(7)(vi) of this section, report the information specified in the applicable paragraphs of this section. (i) Blowdown vent stacks . Report the information specified in paragraph (i) of this section. (ii) Flare stacks . Report the information specified in paragraph (n) of this section. (iii) Centrifugal compressors . Report the information specified in paragraph (o) of this section. (iv) Reciprocating compressors . Report the information specified in paragraph (p) of this section. (v) Equipment leak surveys . Report the information specified in paragraph (q) of this section. (vi) Equipment leaks by population count . Report the information specified in paragraph (r) of this section. (8) Natural gas distribution . For the equipment/activities specified in paragraphs (a)(8)(i) through (a)(8)(iii) of this section, report the infor mation specified in the ap p licable paragraphs of this section. (i) Combustion equipment . Report the information specified in paragraph (z) of this section. (ii) Equipment leak surveys . Report the information specified in paragraph (q) of this section. (ii i) Equipment leaks by population count . Report the information specified in paragraph (r) of this section.

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(b) Natural gas pneumatic devices. You must indicate whether the facility contains the following types of equipment: continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, and intermittent bleed natural gas pneumatic devices. If the facility contains any continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic de vices, or intermittent bleed natural gas pneumatic devices, then you must report the information specified in paragraphs (b)(1) through (b)(4) of this section

. (1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) and (b)(1)( ii) of this section. (i) The total number of devices of each type , determined according to § 98.233(a)(1) and (a)(2). (ii) If the reported value in paragraph (b)(1)(i) of this section is an estimated value determined according to § 98.233(a)(2), then you must report the information specified in paragraphs (b)(1)(ii)(A) through (b)(1)(ii)(C) of this section. (A) The number of devices of each type reported in paragraph (b)(1)(i) of this section that are counted. (B) The number of devices of each type reporte d in paragraph (b)(1)(i) of this section that are estimated (not counted). (C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting. (2) For each type of pneumatic device, the e stimated average number o f hours in the calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) of this section were operating in the calendar year (“T t ” in Equation W

- 1 of this subpart).

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(3) Annual CO 2 emissions, in metric tons CO 2 , for the natural ga s pneumatic devices combined, calculated using Equation W

- 1 of this subpart and § 98 .233(a)(4), and reported in paragraph (b)(1)(i) of this section. (4) Annual CH 4 emissions, in metric tons CH 4 , for the natural gas pneumatic devices combined, calculated us ing Equation W

- 1 of this subpart and § 98 .233(a)(4), and reported in paragraph (b)(1)(i) of this section. (c) Natural gas driven pneumatic pumps . You must indicate whether the facility has any natural gas driven pneumatic pumps. If the facility contains any natural gas driven pneumatic pumps, then you must report the information specified in paragraphs (c)(1) through (c)(4) of this section. (1) Count of natural gas driven pneumatic pumps. (2) Average estimated number of hours in the calendar year the pump s were operational (“T” in Equation W

- 2 of this subpart). (3) Annual CO 2 emissions, in metric tons CO 2 , for all natural gas driven pneumatic pumps combined, calculated according to § 98.233(c)(1) and (c)(2). (4) Annual CH 4 emissions, in metric tons CH 4 , fo r all natural gas driven pneumatic pumps combined, calculated according to § 98.233(c)(1) and (c)(2). (d) Acid gas removal units . You must indicate whether your facility has any acid gas removal units that vent directly to the atmosphere, to a flare or en gine, or to a sulfur recovery plant. If your facility contains any acid gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant, then you must report the information specified in paragraphs (d)(1) and (d) (2) of this section.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 158 of 227 (1) You must report the information specified in paragraphs (d)(1)(i) through (d)(1)(vi) of this section for each acid gas removal unit. (i) A unique name or ID number for the acid gas removal unit. For the onshore petroleum and natura l gas production industry segment, a different name or ID may be used for a single acid gas removal unit for each location it operates at in a given year. (ii) Total feed rate entering the acid gas removal unit, using a meter or engineering estimate based on process knowledge or best available data, in million cubic feet per year. (iii) The calculation method used to calculate CO 2 emissions from the acid gas removal unit, as specified in § 98 .233(d). (iv) Whether any CO 2 emissions from the acid gas removal unit are recovered and transferred outside the facility, as specified in § 98 .233(d)(11). If any CO 2 emissions from the acid gas removal unit were recovered and transferred outside the facility, then you must report the annual quantity of CO 2 , in metric tons CO 2, that was recovered and transferred outside the facility under subpart PP of this part

. (v) Annual CO 2 emissions, in metric tons CO 2 , from the acid gas removal unit, calculated using any one of the calculation met hods specified in § 98 .233(d) and as specified in § 98 .233(d)(10) and (11). (vi) Sub

- basin ID that best represents the wells supplying gas to the unit (for the onshore petroleum and natural gas production industry segment only). (2) You must report informa tion specified in paragraphs (d)(2)(i) through (d)(2)(iii) of this section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, for each acid gas removal unit.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 159 of 227 (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 (d)(2)(i)(B) of this section. (A) Annual average volumetric fraction of CO 2 in the vent g as exiting the acid gas removal unit. (B) Annual volume of gas vented from the acid gas removal unit, in cubic feet. (ii) If you used Calculation Method 3 as specified in § 98 .233(d) to calculate CO 2 emissions from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(D) of this section. (A) Indicate w hich equation was used ( Equation W

- 4A or W

- 4B )

. (B) Annual average volumetric fractio n of CO 2 in the natural gas flowing out of the acid gas removal unit, as specified in Equation W

- 4A or Equation W

- 4B of this subpart. (C) Annual average volumetric fraction of CO 2 content in natural gas flowing into the acid gas removal unit , as specified in Equation W

- 4A or Equation W

- 4B of this subpart. (D) The natural gas flow rate used, as specified in Equation W

- 4A of this subpart, reported as either total annual volume of natural gas flow into the acid gas removal unit in cubic feet at actual conditio ns ; or total annual volume of natural gas flow out of the acid gas removal unit, as specified in Equation W

- 4B of this subpart, in cubic feet at actual conditions. (iii) If you used Calculation Method 4 as specified in § 98 .233(d) to calculate CO 2 emission s from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(iii)(A) through (d)(2)(iii)(L) of this section, as applicable to the simulation software package used. (A) The name of the simulation software package us ed.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 160 of 227 (B) Natural gas feed temperature, in degrees Fahrenheit. (C) Natural gas feed pressure, in pounds per square inch. (D) Natural gas flow rate, in standard cubic feet per minute. (E) Acid gas content of the feed natural gas, in mole percent. (F) Acid ga s content of the outlet natural gas, in mole percent. (G) Unit operating hours, excluding downtime for maintenance or standby, in hours per
year. (H) Exit temperature of the natural gas, in degrees Fahrenheit. (I) Solvent pressure, in pounds per square inc h. (J) Solvent temperature, in degrees Fahrenheit. (K) Solvent circulation rate, in gallons per minute. (L) Solvent weight, in pounds per gallon. (e) Dehydrator s . You must indicate whether your facility contains any of the following equipment: glycol dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 million standard cubic feet per day, glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day, and dehydrators that use desiccant. If your facility contains any of the equipment listed in this paragraph (e), then you must report the applicable information in paragraphs (e)(1) through (e)(3). (1) For each glycol dehydrator that has an annual average dail y 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 paragraphs (e)(1)(i) through (e)(1)(xviii) of this section for the dehydrator.

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(i) A u nique name or ID number for the dehydrator. For the onshore petroleum and natural gas production industry segment, a different name or ID may be used for a single dehydrator for each location it operates at in a given year. (ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, determined by engineering estimate based on best available data. (iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet. (iv) Dehydrator outlet natural gas water conten t, in pounds per million standard cubic feet. (v) Dehydrator absorbent circulation pump type ( e.g. , natural gas pneumatic, air pneumatic, or electric). (vi) Dehydrator absorbent circulation rate, in gallons per minute. (vii) Type of absorbent ( e.g. , trieth ylene glycol (TEG), diethylene gl y col (DEG), or ethylene glycol (EG)). (viii) Whether stripper gas is used in dehydrator. (ix) Whether a flash tank separator is used in dehydrator. (x) Total time the dehydrator is operating, in hours. (xi) Temperature of t he wet natural gas, in degrees Fahrenheit. (xii) Pressure of the wet natural gas, in pounds per square inch gauge. (xiii) Mole fraction of CH 4 in wet natural gas. (xiv) Mole fraction of CO 2 in wet natural gas. (xv) Whether any dehydrator emissions are vented to a vapor recovery device. (xvi) Whether any dehydrator emissions are vented to a flare or regenerator firebox/fire tubes. If any emissions are vented to a flare or regenerator firebox/fire tubes, report t he

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 162 of 227 information specified in paragraphs (e)(1)(xvi)(A) through (e)(1)(xvi)(C) of this section for these emissions from the dehydrator. (A) Annual CO 2 emissions, in metric tons CO 2 , for the dehydrator, calculated according
to § 98 .233(e)(6). (B) Annual CH 4 e missions, in metric tons CH 4 , for the dehydrator, calculated according
to § 98 .233(e)(6). (C) Annual N 2 O emissions, in metric tons N 2 O, for the dehydrator, calculated according
to § 98 .233(e)(6). (xvii) Whether any dehydrator emissions are vented to the at mosphere without being routed to a flare or regenerator firebox/fire tubes. If any emissions are not routed to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(1)(xvii)(A) and (e)(1)(xvii)(B) of th is section for those emissions from the dehydrator. (A) Annual CO 2 emissions, in metric tons CO 2 , for the dehydrator when not venting to a flare or regenerator firebox/fire tubes, calculated according to § 98 .233(e)(1 ) , and , if applicable, (e)(5 ). (B) Annu al 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). (xviii) Sub

- basin ID that best represents the wells supplying gas to the dehydrator (for the onshore petroleum and natural gas production industry segment only). (2) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day ( as specified in § 98 .233(e)(2)), you must report the

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 163 of 227 information specified in paragraphs (e)(2)(i) through (e)(2)(v) of this section for the entire facility. (i) The total number of dehydrators at the facility. (ii) Whether any dehydrator emissions were vented to a vapor recovery device. If any dehydrator emissions were vented to a vapor recovery device, then you must report the total number of dehydrators at the facility that vented to a vapor recovery device. (iii) Whether any dehydrator emissions were vented to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes. If any dehydrator emissions were vented to a control device (s) other than a vapor recovery device or a flare or regenerator firebox/fire tubes, then you must specify the type of con trol device (s) and the total number of dehydrators at the facility that were vented to each type of control device. (iv) 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 paragraphs (e)(2)(iv)(A) through (e)(2)(iv)(D) of this section. (A) The total number of dehydrators venting to a flare or regenerator firebox/fire tubes. (B) Annual CO 2 emissions, in metric tons CO 2 , for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98 .233(e)(6). (C) Annual CH 4 emissions, in metric tons CH 4 , for the dehydrators reported in paragraph (e)( 2)(iv)(A) of this section, calculated according to § 98 .233(e)(6). (D) Annual N 2 O emissions, in metric tons N 2 O, for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98 .233(e)(6).

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 164 of 227 (v) For dehydrator emission s t hat were not vented to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(2)(v)(A) and (e)(2)(v)(B) of this section. (A) Annual CO 2 emissions , in metric tons CO 2 , for emissions from all dehydrators reported in par agraph (e)(2)(i) of this section that were not vented to a flare or regenerator firebox/fire tubes, calculated according to § 98 .233(e)(2), (e)(4), and , if applicable, (e)(5), where emissions are added together for all such dehydrators. (B) Annual CH 4 emissions , in metric tons CH 4 , for emissions from all dehydrators reported in paragraph (e)(2)(i) of this section that were not vented to a flare or regenerator firebox/fire tubes, calculated according to § 98 .233(e)(2), (e)(4), and , if applicable, (e)(5) , where emissions are added together for all such dehydrators. (3) For dehydrators that use desiccant (as specified in § 98 .233(e)(3)), you must report the information specified in paragraphs (e)(3)(i) through (e)(3)(iii) of this section for the entire fac ility. (i) The same information specified in paragraphs (e)(2)(i) through (e)(2)(iv) of this section for glycol dehydrators, and report the information under this paragraph for dehydrators that use desiccant. (ii) Annual CO 2 emissions, in metric tons CO 2 , for emissions from all desiccant dehydrators reported under paragraph (e)(3)(i) of this section that are not venting to a flare or regenerator firebox/fire tubes, calculated according to § 98 .233(e)(3), (e)(4), and , if applicable, (e)(5), and summing for a ll 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

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 165 of 227 regenerator firebox/fire tubes, calculated according to § 9 8 .233(e)(3), (e)(4), and , if applicable, (e)(5), and summing for all such dehydrators. (f) Liquids unloading . You must indicate whether well venting for liquids unloading occurs at your facility, and if so, which 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 information specified in paragraph (f)(1) of this section. If the facility performs liquids unlo ading 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 ga s emissions from well venting for liquids unloading, report the information specified in paragraphs (f)(1)(i) through (f)(1)(xii) of this section. Report information separately for wells with plunger lifts and wells without plunger lifts. (i) Sub

- basin ID. (ii) Well tubing diameter and pressure group ID. (iii) Plunger lift indicator. (iv) Count of wells vented to the atmosphere for the sub

- basin/well tubing diameter and
pressure group . (v) Percentage of wells for which the monitoring period used to determin e the cumulative amount of time venting was not the full calendar year. (vi) Cumulative amount of time wells were vented (sum of “T p ” from Equation W

- 7A or
W

- 7B of this subpart), in hours. (vii) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all wells in the sub

- basin/well tubing diameter and pressure group .
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 166 of 227 (viii) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98 .233(f)(1). (ix) Annual CO 2 e missions, in metric tons CO 2 , from well venting for liquids unloading, calculated according to § 98 .233(f)(1) and § 98 .233(f)(4). (x) Annual CH 4 emissions, in metric tons CH 4 , from well venting for liquids unloading, calculated according to § 98 .233(f)( 1) and § 98 .233(f)(4). (xi) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xi)(A) through (f)(1)(xi)(E) of this section for each individual well not using a plunger lift th at was tested during the year. (A) API Well N umber of tested well. (B) Casing pressure, in pounds per square inch absolute. (C) Internal casing diameter, in inches. (D) Measured depth of the well, in feet. (E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour. (xii) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xii)(A) through (f)(1)(xii)(E) of this section for each individual well using a plunger lift that was tested during the year. (A) API W ell N umber. (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.

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(E) Averag e flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour. (2) For each sub

- basin for which you used Calculation Method 2 or 3 (as specified in § 93.233(f)) to calculate natural gas emissions from well vent ing for liquids unloading, you must report the information in (f)(2)(i) through (f)(2)(x) of this section. Report information separately for each calculation method. (i) Sub

- basin ID. (ii) Calculation method. (iii) Plunger lift indicator. (iv) Number of we lls vented to the atmosphere. (v) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all wells. (vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98 .233(f)(2) or § 98 .233(f)(3), as applicable. (vii) Annual CO 2 emissions, in metric tons CO 2 , from well venting for liquids unloading, calculated according to § 98 .233(f)(2) or § 98 .233(f)(3), as applicable, and § 98 .233(f)(4). (viii) Annual CH 4 emissions, in metric tons CH 4 , from well venting for liquids unloading, calculated according to § 98 .233(f) (2) or § 98 .233(f)(3), as applicable, and § 98 .233(f)(4). (ix) For wells without plunger lifts, the average internal casing diameter, in inches. ( x) For wells with plunger lifts, the average internal tubing diameter, in inches. (g) Completions and workovers with hydraulic fracturing

. You must indicate whether
your facility had any gas well completions or workovers with hydraulic fracturing during t he calendar year. If your facility had gas well completions or workovers with hydraulic fracturing

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 168 of 227 during the calendar year, then you must report information specified in paragraphs (g)(1) through (g)(10) of this section, for each sub

- basin and well type c ombination. Report information separately for completions and workovers. (1) Sub

- basin ID. (2) Well type combination

. (3) Number of completions or workovers in the sub

- basin 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 paragraphs (g)(5)(i) and (g)(5)(ii) of this section. (i) Cumulative gas flowback time, in hours, from when gas is first detected until suff icient quantities are present to enable separation, and the c umulative flowback time, in hours, after sufficient quantities of gas are present to enable separation ( sum of “T p,i ” and sum of “T p,s ” values used in Equation W

- 10A). 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 included in this number. If you elect to delay reporting of this data element, you must report by the date specified in § 98

. 236(cc) t he total number of hours of flowback from all wells during completions or workovers and the API Well Number(s) for the well ( s ) included in the number

. (ii) For the measured well(s), the flowback rate, in standard cubic feet per hour (average of “FR s,p ” val ues used in Equation W

- 12A). 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 rate during well

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 169 of 227 completion or workover and the API Well Number(s) for the well ( s ) included in the
measurement

. (6) If you used Equation W

- 10B to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(6)(i) and (g)(6)(ii) of this section. (i) V ented natural gas volume, in standard cubic feet, for each well i n the sub

- basin (“FV s,p ” in Equation W

- 10B). (ii) Flow rate at the beginning of the period of time when sufficient quantities of gas are present to enable separation, in standard cubic feet per hour, for each well in the sub

- basin (“FR p,i ” in Equation W

- 10 B). (7) Annual gas emissions, in standard cubic feet (“E s,n ” in Equation W

- 10A or W

- 10B). (8) Annual CO 2 emissions, in metric tons CO 2 . (9) Annual CH 4 emissions, in metric tons CH 4 . (10) If the well emissions were vented to a flare, then you must report the total N 2 O emissions, in metric tons N 2 O. (h) Completions and workovers without hydraulic fracturing . You must indicate whether the facility had any gas well completions without hydraulic fracturing or any gas well workovers without hydraulic fracturin g, and if the activities occurred with or without flaring. If the facility had gas well completions or workovers without hydraulic fracturing, then you must report the information specified in paragraphs (h)(1) through (h)(4) of this section, as applicable

. (1) For each sub

- basin with gas well completions without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(1)(i) through (h)(1)(vi) of this section. (i) Sub

- basin ID.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 170 of 227 (ii) Number of well completions that vented gas directly to the atmosphere without flaring. (iii) Total number of hours that gas vented directly to the atmosphere during venting for all completions in the sub

- basin category (the sum of all “T p ” for completions that vented to the atmosphere as used i n Equation W

- 13B). (iv) Average daily gas production rate for all completions without hydraulic fracturing in the sub

- basin without flaring, in standard cubic feet per hour (average of all “V p ” used in Equation W

- 13B). You may delay 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) th e measured average daily gas production rate for all wells during completions and t he API Well Number(s) for the well ( s ) included in the measurement

. (v) Annual CO 2 emissions, in metric tons CO 2 , that resulted from completions venting gas directly to the a tmosphere (“E s,p ” from Equation W

- 13B for completions that vented directly to the atmosphere, converted to mass emissions according to § 98.233(h)(1)). (vi) Annual CH 4 emissions, in metric tons CH 4 , that resulted from completions venting gas directly to th e atmosphere ( “ E s,p ” from Equation W

- 13B for completions that vented directly to the atmosphere, converted to mass emissions according to § 98.233(h)(1) )

. (2) For each sub

- basin with gas well completions without hydraulic fracturing and with flaring, report the information specified in paragraphs (h)(2)(i) through (h)(2)(vii) of this section. (i) Sub

- basin ID. (ii) Number of well completions that flared gas.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 171 of 227 (iii) Total number of hours that gas vented to a flare during venting for all completions in th e sub

- basin category (the sum of all “T p ” for completions that vented to a flare from Equation
W

- 13B). (iv) Average daily gas production rate for all completions without hydraulic fracturing in the sub

- basin with flaring, in standard cubic feet per hour (t he average of all “V p ” from Equation
W

- 13B). You may delay 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 report ing of this data element, you must report by the date specified in § 98

. 236(cc) the measured average daily gas production rate for all wells during completions and
t he API Well Number(s) for the well ( s ) included in the measurement

. (v) Annual CO 2 emissions , in metric tons CO 2 , that resulted from completions that flared gas calculated according to § 98.233(h)(2). (vi) Annual CH 4 emissions, in metric tons CH 4 , that resulted from completions that flared gas calculated according to § 98.233(h)(2). (vii) Annual N 2 O emissions, in metric tons N 2 O, that resulted from completions that flared gas calculated according to § 98.233(h)(2). (3) For each sub

- basin with gas well workovers without hydraulic fracturing and without flaring, report the information specified in p aragraphs (h)(3)(i) through (h)(3)(iv) of this section. (i) Sub

- basin ID. (ii) Number of workovers that vented gas to the atmosphere without flaring. (iii) Annual CO 2 emissions, in metric tons CO 2 per year, that resulted from workovers venting gas directly to the atmosphere (“E s,wo ” in Equation W

- 13A for workovers that vented directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)).

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(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 emissions as specified in § 98.233(h)(1)). (4) For each sub

- basin with gas well workovers without hydraulic fracturing and with flaring, report the information specified in paragraphs (h)(4)(i) through (h)(4)(v) of this section. (i) Sub

- basin ID. (ii) Number of workovers that flared gas. (iii) Annual CO 2 emissions, in metric tons CO 2 per year, that resulted from workovers that flared gas calculated as specified in § 98.233(h)(2). (iv) Annual CH 4 emissions, in metric tons CH 4 per year, that resulted from workovers that flared gas, calculated as specified in § 98.233(h)(2). (v) Annual N 2 O emissions, in metric tons N 2 O per year, that resulted from workovers that flared gas calculated as specified in § 98.233(h)(2). (i ) Blowdown vent stacks . You must indicate whether your facility has blowdown vent stacks. If your facility has blowdown vent stacks, then you must report whether emissions were calculated by equipment or event type or by using flow 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, all blowdown vent stacks for which emissions were calculated by equipment or event type . If you calculated emissions using flow meters for any blowdown vent stacks , then y ou must report the information specified in paragraph (i)(2) of this section considering, in aggregate, all blowdown vent stacks for which emissions were calculated using flow meters

.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 173 of 227
(1) Report by equipment or event type . If you calculated 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 paragraphs (i)(1)(i) through (i)(1)(iii) of this section for each equipment or event type. If a blowdo wn event resulted in emissions from multiple equipment types , and the emissions cannot be apportioned to the different equipment types , then
you may report the information in paragraphs (i)(1)(i) through (i)(1)(iii) of this section for the equipment type t hat 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 metric tons CO 2 , calculated according to § 98 .233(i)(2)(iii). (iii) Annual CH 4 emissions for the equipment or event type, in metric tons CH 4 , calculated according to § 98.233(i)(2)(iii). (2) Report by flow meter . If you elect to calculate emissions from blowdown vent stacks by using a flow meter according to § 98.233(i)(3), then you must report the information specified in paragraphs ( i)(2)(i) and (i)(2)(ii) of this section for the facility. (i) Annual CO 2 emissions from all blowdown vent stacks at the facility for which emissions were calculated using flow meters , in metric tons CO 2 (the sum of all CO 2 mass emission values calculated a ccording to § 98 .233(i)(3), for all flow meters). (ii) Annual CH 4 emissions from all blowdown vent stacks at the facility for which emissions were calculated using flow meters , in metric tons CH 4 , (the sum of all CH 4 mass emission values calculated accordi ng to § 98 .233(i)(3), for all flow meters).

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 174 of 227 (j) Onshore production storage tanks . You must indicate whether your facility sends produced oil to atmospheric tanks. If your facility sends produced oil to atmospheric tanks, then you must indicate which Calcul ation Method(s) you used to calculate GHG emissions, and you must report the information specified in paragraphs (j)(1) and (j)(2) of this section as applicable.
If you used Calculation Method 1 or Calculation Method 2, and any atmospheric tanks were observed to have malfunctioning dump valves during the calendar year, then you must indicate that dump valves were malfunctioning and you must report the information specified in paragraph (j)(3) of this section. (1) If you use d Calculation Method 1 or Calculation Method 2 to calculate GHG emissions, then you must report the information specified in paragraphs (j)(1)(i) through (j)(1)(xiv) of this section for each sub

- basin and by calculation method. (i) Sub

- basin ID. (ii) Calcu lation method used, and name of the software package used if using Calculation Method 1. (iii) The total annual oil volume from gas

- liquid separators and direct from wells that is sent to applicable onshore production storage tanks, in barrels. You may del ay 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 greater than or equal to 10 barrels per day and flowing to gas

- liquid separators or dire ct to storage 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 t he API W ell N umber(s) for the well ( s ) included in this volume

. (iv) The average gas

- liquid separator temperature, in degrees Fahrenheit

. (v) The average gas

- liquid separator pressure, in pounds per square inch gauge.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 175 of 227 (vi) The average sales oil or stabilized oil API gravity, in degrees. (vii) The minimum and maximum concentration (mole fr action) of CO 2 in flash gas from onshore production storage tanks. (viii) The minimum and maximum concentration (mole fraction) of CH 4 in flash gas from onshore production storage tanks. (ix) The number of wells sending oil to gas

- liquid separators or dire ctly to atmospheric tanks. (x) The number of atmospheric tanks

. (xi) An estimate of the number of atmospheric tanks, not on well

- pads, receiving your oil. (xii) If any emissions from the atmospheric tanks at your facility were controlled with vapor recovery systems, then you must report the information specified in paragraphs (j)(1)(xii)(A) through (j)(1)(xii)(E) of this section. (A) The number of atmospheric tanks that control emissions with vapor recovery system s. (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.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 176 of 227 (xiii) If any atmospheric tanks at your facility vente d gas directly to the atmosphere without using a vapor recovery system or without flaring, then you must report the information specified in paragraphs (j)(1)(xiii)(A) through (j)(1)(xiii)(C) of this section. (A) The number of atmospheric tanks that vented gas directly to the atmosphere without using a vapor recovery system or without flaring. (B) Annual CO 2 emissions, in metric tons CO 2 , that resulted from venting gas directly to the atmosphere. (C) Annual CH 4 emissions, in metric tons CH 4 , that resulted f rom venting gas directly to the atmosphere. (xiv) If you controlled emissions from any atmospheric tanks at your facility with one or more flares, then you must report the information specified in paragraphs (j)(1)(xiv)(A) through (j)(1)(xiv)(D) of this se ction. (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 atm ospheric tanks that controlled emissions with one or more flares. (D) Annual N 2 O emissions, in metric tons N 2 O, from atmospheric tanks that controlled emissions with one or more flares. (2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the information specified in paragraph s (j)(2)(i) through (j)(2)(iii) of this section

.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 177 of 227 (i) Report the information specified in paragraphs (j)(2)(i)(A) through (j)(2)(i)(F) of this section, at the basin level, for atmospheric tanks where emi ssions were calculated using Calculation Method 3. (A) The total annual oil throughput that is sent to all atmospheric tanks in 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 send oil to atmospheric tanks. If you elect to delay reporting of this data element, you must report by the date specified in § 98

. 236(cc) the t otal annual oil throughput from all wells and t he API Well Number(s) for the well ( s ) included in this volume

. (B) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the basin that c ontrolled emissions with flares. (C) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the basin that controlled emissions with vapor recovery systems. (D) The number of atmospheri c tanks in the basin. (E) The number of wells with gas

- liquid separators (“Count” from Equation W

- 15 of this subpart) in the basin. (F) The number of wells without gas

- liquid separators (“Count” from Equation W

- 15 of this subpart) in the basin. (ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (j)(2)(ii)(D) of this section for each sub

- basin with atmospheric tanks whose emissions were calculated using Calculation Method 3 and that did not control emissions with flares. (A) Sub

- basin ID.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 178 of 227 (B) The number of atmospheric tanks in the sub

- basin that did not control emissions with flares. (C) Annual CO 2 emissions, in metric tons CO 2 , from atmospheric tanks in the sub

- basin that did not control emissions with flares, calculated 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 , calculated using Equation W

- 15 of this subpart and adjus ted for vapor recovery, if applicable

. (iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (j)(2)(iii)(E) of this section for each sub

- basin with atmospheric tanks whose emissions were calculated using Calculation Method 3 and that controlled emissions with flares. (A) Sub

- basin ID. (B) The number of atmospheric tanks in the sub

- basin that controlled emissions with flares. (C) Annual CO 2 emissions, in metric tons CO 2 , from atmospheric tanks that controlled emissions with flares. (D) Annual CH 4 emissions, in metric tons CH 4 , from atmospheric tanks that controlled emissions with flares. (E) Annual N 2 O emissions, in metric tons N 2 O, from atmospheric tanks that controlled emissions with flares. (3) If you used Calculation Method 1 or Cal culation Method 2, and any gas - liquid separator liquid dump values did not close properly during the calendar year, then you must

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 179 of 227 report the information specified in paragraphs (j)(3)(i) through (j)(3)(iv) of this section for each sub

- basin

. (i) The total number of gas

- liquid separators whose liquid dump valves did not close properly during the calendar year. (ii) The total time the dump valves on gas

- liquid separators did not close properly in the calendar year, in hours ( sum of the “T n ” values used in Equ ation W

- 16 of this subpart). (iii) Annual CO 2 emissions, in metric tons CO 2 , that resulted from dump valves on gas

liquid separators not closing properly during the calendar year, calculated using Equation W

- 16 of this subpart. (iv) Annual CH 4 emissions, i n metric tons CH 4 , that resulted from the dump valves on
gas - liquid separators not closing properly during the calendar year, calculated using Equation W

16 of this subpart. (k) Transmission storage tanks . You must indicate whether your facility contains any transmission storage tanks. If your facility contains at least one transmission storage tank, then you must report the information specified in paragraphs (k)(1) through (k)(3) of this section for each transmission storage tank vent stack. (1) For each transmission storage tank vent stack, report the information specified in (k)(1)(i) through (k)(1)(iv) of this section. (i) The unique name or ID number for the transmission storage tank vent stack. (ii) Method used to determine if dump valve leakage occurred. (iii) Indicate whether scrubber dump valve leakage occurred for the transmission storage tank vent according to § 98.233(k)(2)

. (iv) Indicat e if there is a flare attached to the transmission storage tank vent stack.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 180 of 227
(2) If scrubber dump valve leakage occurred for a transmission 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 (k)(2)(v) of this section for each transmission storage vent stack where scrubber dump valve leakage occurred. (i) Method used to measure the leak rate. (ii) Measured leak rate (average leak rate from a continuous flow measurem ent 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 (k)( 4 ). (v) Annual CH 4 emissions, in metric tons CH 4 , that resulted from venting gas directly to the atmosphere, calcu lated according to § 98 .233(k)(1) through (k)( 4 ). (3) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii), and the vent stack vented to a flare during the calendar year, then you must rep ort the information specified in paragraphs (k)(3)(i) through (k)(3)(vi) of this section

. (i) Method used to measure the leak rate. (ii) Measured leakage rate (average leak rate from a continuous flow measurement device) in standard cubic feet per hour.

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( iii) Duration of time that flaring occurred in hours , as defined 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 flaring gas, calculated

ac cording 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 performed gas well or oil well testing, and if the testing of gas wells or oil wells resulted in vented or flared emissions during the calendar year. If you performed well testing that resulted in vented or flared emissions during the calendar year, then you must report the information specified in paragraphs (l)(1) through (l)(4) of this section , as applicable. (1) If you used Equation W

- 17A to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are not vented to a flare, then you must report the information specified in paragraphs (l)(1)(i) through (l)(1)(vi) of this section. (i) Number of wells tested in the calendar year. (ii) Average number of well testing days per well for well(s) tested in the calendar year. (iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil. (iv) Average flow rate for well(s) tested, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 182 of 227 element, you must report by the date specified in § 98

. 236(cc) the measured average flow rate for well(s) tested and t he API Well Number(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). (vi) Annual CH 4 emissions, in metric tons CH 4 , calculated accor ding 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) thr ough (l)(2)(vii) of this section. (i) Number of wells tested in the calendar year. (ii) Average number of well testing days per well for well(s) tested in the calendar year. (iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil. (iv) Average flow rate for well(s) tested, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are 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 flow rate for well(s) tested and t he API Well Number(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). (vi) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98 .233(l). (vii) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98 .233(l). (3) If you used Equation W

- 17B to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were not vented to a flare, then you must report the information specified in paragraphs (l)(3)(i) through (l)(3)(v) of this section. (i) Number of wells tested i n the calendar year. (ii) Average number of well testing days per well for well(s) tested in the calendar year.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 183 of 227 (iii) Average annual production rate for well(s) tested, in actual cubic feet per day. You may delay reporting of this data element if you indic ate in the annual report that wildcat wells and/or delineation wells are the only wells that are 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 t he API Well Number(s) for the well ( s ) included in the
measurement

. (iv) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98 .233(l). (v) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98 .233(l). (4) If you used Equation W

- 17B to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were vented to a flare, then you must report the information specified in paragraphs (l)(4)(i) through (l)(4) (vi) of this section. (i) Number of wells tested in calendar year. (ii) Average number of well testing days per well for well(s) tested in the calendar year. (iii) Average annual production rate for well(s) tested, in actual cubic feet per day. You may del ay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in § 98

. 236(c c) the measured average annual production rate for well(s) tested and t he API Well Number(s) for the well ( s ) included in the
measurement

. (iv) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98 .233(l). (v) Annual CH 4 emissions, in metri c tons CH 4 , calculated according to § 98 .233(l). (vi) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98 .233(l).

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(m) Associated natural gas . You must indicate whether any associated gas was vented or flared during the calendar year. If associated gas was vented or flared during the calendar year, then you must report the information specified in paragraphs (m)(1) through (m)( 8 ) of this section for each sub

- basin. (1) Sub

- basin ID. (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 feet of gas per barrel of oil (average of the “GOR” values used in Equati on W

- 18 of this subpart). (5) Volume of oil produced, in barrels, in the calendar year during the time periods in which associated gas was vented or flared (the sum of “V p,q ” used in Equation W

- 18 of this subpart). 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 specified in § 98

. 236( cc) the volume of oil produced for well(s) with associated gas venting and flaring and t he API Well Number(s) for the well ( s ) included in the measurement

. (6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year during time periods in which associated gas was vented or flared (the sum of “SG” values used in Equation W

- 18 of § 98.233(m) ). You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells from whi ch associated gas was vented or flared. If you elect to delay reporting of this data element, you must report by the date specified in § 98

. 236(cc) the measured total volume of associated gas sent to sales for

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 185 of 227 well(s) with associated gas venting and flarin g and t he API Well Number(s) for the well ( s ) included in the measurement

. (7 ) If you had associated gas emissions vented directly to the atmosphere without flaring, then you must report the information specified in paragraphs (m)( 7 )(i) through (m)( 7 )(iii) of this section for each sub

- basin. (i) Total number of wells for which associated gas was vented directly to the atmosphere without flaring. (ii) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98 .233(m)(3) and (m)(4). (iii) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98 .233(m)(3) and (m)(4). (8 ) If you had associated gas emissions that were flared, then you must report the information specified in paragraphs (m)( 8 )(i) through (m)( 8 )(iv) of this section for each sub

basin. (i) Total number of wells for which associated gas was flared. (ii) Annual CO 2 emissions, in metric tons CO 2 , calculated according to § 98 .233(m)(5). (iii) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98 .233(m)(5). (iv) An nual N 2 O emissions, in metric tons N 2 O, calculated according to § 98 .233(m)(5). (n) Flare stacks . You must indicate if your facility contains any flare stacks. You must report the information specified in paragraphs (n)( 1) through (n)(12) of this section for each flare stack at your facility, and for each industry segment applicable to your facility.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 186 of 227 (1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production industry segment, a differe nt name or ID may be used for a single flare stack for each location where it operates at in a given calendar year. (2) Indicate whether the flare stack has a continuous flow measurement device. (3) Indicate whether the flare stack has a continuous gas com position analyzer on feed gas to the flare. (4) Volume of gas sent to the flare, in standard cubic feet (“ V s ” in Equation s W

- 19 and
W

- 20 of this subpart). (5) Fraction of the feed gas sent to an un

- lit flare (“Z u ” in Equation W

- 19 of this subpart). (6) Fla re combustion efficiency, expressed as the fraction of gas combusted by a burning flare. (7) Mole fraction of CH 4 in the feed gas to the flare (“X CH4 ” in Equation W

- 19 of this subpart). (8) Mole fraction of CO 2 in the feed gas to the flare (“X CO2 ” in Equat ion W

- 20 of this subpart). (9) Annual CO 2 emissions, in metric tons CO 2 (refer to Equation W

- 20 of this subpart). (10) Annual CH 4 emissions, in metric tons CH 4 (refer to Equation W

- 19 of this subpart). (11) Annual N 2 O emissions, in metric tons N 2 O (refer to Equation W

- 40 of this subpart). (12) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used to measure emissions from the flare, then you are not required to report N 2 O and CH 4 emissions for the flare stack. (o) Centrif ugal compressors . You must indicate whether your facility has centrifugal compressors. You must report the information specified in paragraphs (o)(1) and (o)(2) of this

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 187 of 227 section for all centrifugal compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98 .233(o)(2) or (o)(4), you must report the information specified in paragraph (o)(3) of this section. For each compressor source or manifolded group of c ompressor sources that you conduct continuous monitoring as specified in § 98 .233(o)(3) or (o)(5), you must report the information specified in paragraph (o)(4) of this section. Centrifugal compressors in onshore petroleum and natural gas production are no t required to report information in paragraphs (o)(1) through (o)(4) of this section and instead must report the information specified in paragraph (o)(5) of this section. (1) Compressor activity data . Report the information specified in paragraphs (o)( 1)(i) through (o)(1)(x i v) of this section for each centrifugal compressor located at your facility. (i) Unique name or ID for the centrifugal compressor. (ii) Hours in operating

- mode. (iii) Hours in not

- operating

- depressurized

- mode. (iv) Indicate whether t he compressor was measured in 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 are routed to a flare. (viii) Indicate which, if any , compressor sources have vapor recovery. (ix) Indicate which, if any , compressor source emission s are captured for fuel use or are routed to a thermal oxidizer. (x) Indicate wh ether the compressor has blind flanges installed and associated dates

.
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 188 of 227 (xi) Indicate whether the compressor has wet or dry seals. (xii) If the compressor has wet seals, the number of wet seals. (xiii) Power output of the compressor driver (hp). (xiv) Indic ate whether the compressor had a scheduled depressurized shutdown during the reporting year. (2) Compressor source . (i) For each compressor source at each compressor, report the information specified in paragraphs (o)(2)(i)(A) through (o)(2)(i)(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, isolation valve, or blowdown valve). (C) Unique name or ID for the leak or vent. If the l eak or ven t is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor

source in the manifolded group . If multiple compressor sources are released through a single vent for which continuous measurements are used, use t he same leak or vent ID for each compressor source released via the measured vent. For 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 informa tion specif i ed in paragraphs (o)(2)(ii)(A) through (o)(2)(ii)(E) of this section. (A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are release d 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 (o)(4) was conducted on the leak or vent.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 189 of 227
(C) Indicate whether continuous m easurements as identified in § 98 .233(o)(3) or (o)(5) were conducted on the leak or vent. (D) Report emissions as specified in paragraphs (o)(2)(ii)( D )( 1 ) and (o)(2)(ii)(D) ( 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 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, combustion, or vapor recovery, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device

. (3) As found measurement sample data . If the measurement methods specified in § 98 .233(o)(2) or (o)(4) are co nducted, report the information 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. (i) For each as found measurement p erformed on a leak or vent, report the information specified in paragraphs (o)(3)(i)(A) through (o)(3)(i)( F ) of this section. (A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section. (B) Measurement date. (C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions. (D) Measured f low rate, in standard cubic feet per hour.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 190 of 227 (E) For each compressor attached to the leak or vent, 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 comingling with non

- compressor emission sources. (ii) For each compressor mode

- source combination where a reporter emission factor as calculated in E quation W

- 23 was used to calculate emissions in Equation W

- 22, r eport the information specified in paragraphs (o)(3)(ii)(A) through (o)(3)(ii)(D) of this section (A) The compressor mode

- source combination. (B) The compressor mode

- source combination reporter emission factor, in standard cubic feet per hour (EF s,m in Equ ation W

- 23). (C) The total number of compressors measured in the compressor mode

- source combination in the current reporting year and the preceding two reporting years (Count m in Equation W

- 23). (D) Indicate whether the compressor mode

- source combination r eporter emission factor is facility

- specific or based on all of the reporter’s applicable facilities

. (4) Continuous measurement data . If the measurement methods specified in § 98 .233(o)(3) or (o)(5) are conducted, report the information specified in para graphs (o)(4)(i) through (o)(4)(i v ) of this section for each continuous measurement conducted on each leak or vent associated with each compressor source or manifolded group of compressor sources

. (i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section. (ii) Measured volume of flow during the reporting year, in million standard cubic feet.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 191 of 227 (iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allo wed for in § 98 .233(o)(3)(ii) and (o)(5)(iii). (iv) If the measurement is for a manifolded group of compressor sources , indicate whether the measurement location is prior to or after comingling with non

- compressor emission

sources. (5) Onshore petroleum an d natural gas production

. Centrifugal compressors with wet seal degassing vents in onshore petroleum and natural gas production must report the information specified in paragraphs (o)(5)(i) through (o)(5)(iii) of this section. (i) Number of centrifugal com pressors that have wet seal oil degassing vents. (ii) Annual CO 2 emissions, in metric tons CO 2 , from centrifugal compressors with wet seal oil degassing vents. (iii) Annual CH 4 emissions, in metric tons CH 4 , from centrifugal compressors with wet seal oil d egassing vents. (p) Reciprocating compressors . You must indicate whether your facility has reciprocating compressors. You must report the information specified in paragraphs (p)(1) and (p)(2) of this section for all reciprocating compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98 .233(p)(2) or (p)(4), you must report the information specified in paragraph (p)(3) of this section. For each co mpressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98 .233(p)(3) or (p)(5), you must report the information specified in paragraph (p)(4) of this section. Reciprocating compressors in onshore p etroleum and natural gas production are not required to report information in

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 192 of 227 paragraphs (p)(1) through (p)(4) of this section and instead must report the information specified in paragraph (p)(5) of this section. (1) Compressor activity data . Report the information specified in paragraphs (p)(1)(i) through (p)(1)(x i v) of this section for each reciprocating compressor located at your facility. (i) Unique name or ID for the reciprocating compressor. (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 in standby

- pressurized

- mode. (vii) Indicate whether the compress or was measured in not

- operating

- depressurized

mode. (viii) Indicate which, if any , compressor sources are 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 emission s are captured for fuel use or are routed to a thermal oxidizer. (xii) Indicate whether the compressor has blind flanges installed and associated dates

. (xiii) Power output of the compressor driver (hp). (xiv) Indicate whether the compressor had a scheduled depressurized shutdown during the reporting year

.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 193 of 227
(2) Compressor source . (i) For each compressor source at each compressor, report the information spec ified in paragraphs (p)(2)(i)(A) through (p)(2)(i)(C) of this section. (A) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of this section. (B) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing)

. (C) Unique name or ID for the leak or vent. If the l eak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor

source in the manifolded group

. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each co mpressor source. ( ii) For each leak or vent , report the information specif i ed in paragraphs (p)(2)(ii)(A) through (p)(2)(ii)(E) of this section. (A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sourc es and whether the emissions 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 (p)(4)

was co nducted on the leak or vent. (C) Indicate whether continuous measurements as identified in § 98 .233(p)(3) or (p)(5) were conducted on the leak or vent. (D) Report emissions as specified in paragraphs (p)(2)(ii)( D )( 1 ) and (p)(2)(ii)( D )( 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

.
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( 1 ) Annual CO 2 emissions, in metric tons CO 2 . ( 2 ) Annual CH 4 emissions, in metric tons CH 4 . (E) If t he leak or vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device

. (3) As found measurement sample data . If the measure ment methods specified in § 98 .233(p)(2) or (p)(4) are conducted, report the information 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 leak or vent, report the information specified in paragraphs (p)(3)(i)(A) through (p)(3)(i)( F ) of this section. (A) Name or ID of leak or vent. Use same leak or vent ID as in para graph (p)(2)(i)(C) of this section. (B) Measurement date. (C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions. (D) Measured flow rate, in standa rd cubic feet per hour. (E) For each compressor attached to the leak or vent, 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 locati on is prior to or after comingling with non

- compressor emission sources.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 195 of 227 (ii) For each compressor mode

- source combination where a reporter emission factor as calculated in E quation W

- 28 was used to calculate emissions in Equation W

- 27, report the informat ion specified in paragraphs (p)(3)(ii)(A) through (p)(3)(ii)(D) of this section (A) The compressor mode

- source combination. (B) The compressor mode

- source combination reporter emission factor, in standard cubic feet per hour (EF s,m in Equation W

- 28). (C) T he total number of compressors measured in the compressor mode

- source combination in the current reporting year and the preceding two reporting years (Count m in Equation W

- 28). (D) Indicate whether the compressor mode

- source combination reporter emission f actor is facility

- specific or based on all of the reporter’s applicable facilities. (4) Continuous measurement data . If the measurement methods specified in § 98 .233(p)(3) or (p)(5) are conducted, report the information specified in paragraphs (p)(4)(i) th rough (p)(4)(i v ) of this section for each continuous measurement conducted on each leak or vent associated with each compressor source or manifolded group of compressor sources

. (i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)( 2)(i)(C) of this section. (ii) Measured volume of flow during the reporting year, 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 § 98 .23 3(p)(3)(ii) and (p)(5)(iii). (iv) If the measurement is for a manifolded group of compressor sources , indicate whether the measurement location is prior to or after comingling with non

- compressor emission

sources.
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 196 of 227
(5) Onshore petroleum and natural gas prod uction

. Reciprocating compressors in onshore petroleum and natural gas production must report the information specified in paragraphs (p)(5)(i) through (p)(5)(iii) of this section. (i) Number of reciprocating compressors. (ii) Annual CO 2 emissions, in metr ic tons CO 2 , from reciprocating compressors. (iii) Annual CH 4 emissions, in metric tons CH 4 , from reciprocating compressors. (q) Equipment leak surveys . If your facility is subject to the requirements of § 98 .233(q), then you must report the information specified in paragraphs (q)(1) and (q)(2) of this section. Natural gas distribution facilities with emission sources listed in § 98 .232(i)(1) must also report the information specified in paragraph (q)(3) of this section. (1) You must report the informatio n specified in paragraphs (q)(1)(i) and (q)(1) (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 calendar year. (ii) Natural gas distribution facilities performing equipment leak surveys across a multiple year leak survey cycle must report the number of years in the leak survey cycle. (2) You must indicate whether your facility contains 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 facility, you must report the information specified in paragraphs (q)(2)(i) through (q)(2)(v) of this section. If a component type is located at your facility and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (q)(2)(v) of this section but report a zero (“0”) for the information required according to paragraphs (q)(2)(iii), (q)(2) (iv), and (q)(2)(v) of this section.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 197 of 227 (i) Component type. (ii) Total number of the surveyed component type that were identified as leaking in the calendar year (“x p ” in Equation W

- 30 of this subpart for the component type). (iii) Average time the surveyed components are assumed to be leaking and operational, in hours (average of “T p,z ” from Equation W

- 30 of this subpart for the component type). (iv) Annual CO 2 emissions, in metric tons CO 2 , for the component type as calculated using Equation W

- 30 (for surve yed 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)

. (3) Natural gas distribution facilities with emission sources listed in § 98 .232( i )( 1 ) must also report the information specified in paragraphs (q)(3)(i) through (q)(3)(viii) and, if applicable, (q)(3)(ix) of this s ection

. (i) Number of above grade transmission

- distribution transfer stations surveyed in the calendar year. (ii) Number of meter/regulat or 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 surveyed in the calendar year w ere operational, in hours (average of “T w,y ” from Equation W

- 31 of this subpart, for the current calendar year). (iv) Number of above grade transmission

- distribution transfer stations surveyed in the current leak survey cycle.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 198 of 227 (v) Number of meter/regulator runs at above grade transmission

- distribution transfer stations surveyed in current leak survey cycle (sum of “Count MR,y ” from Equation W

- 31 of this subpart, for all calendar years in the current leak survey cycle). (vi) Average time that meter/regulator runs surveyed in the current leak survey cycle were operational, in hours (average of “T w,y ” from Equation W

- 31 of this subpart, for all years included in the leak survey cycle). (vii) Meter/regulator run CO 2 emission factor based on all surveyed transmiss ion

distribution transfer stations in the current leak survey cycle, in standard cubic feet of CO 2 per operational hour of all meter/regulator run s (“EF s,MR,i ” for CO 2 calculated using Equation W

- 31 of this subpart). (viii) Meter/regulator run CH 4 emission factor based on all surveyed transmission

distribution transfer stations in the current leak survey cycle, in standard cubic feet of CH 4 per operational hour of all meter/regulator run s (“EF s,MR,i ” for CH 4 calculated using Equation W

- 31 of this subpart). (ix) If your natural gas distribution facility performs equipment leak surveys across a multiple year leak survey cycle, you must also report: (A) The total number of meter/regulator runs at above grade transmission

- distribution transfer stations at your f acility (“Count MR ” in Equation W

- 32B of this subpart)

. (B) Average estimated time that each meter/regulator run at above grade transmission

distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T w,avg ” in E quation W

- 32B of this subpart)

. (C) Annual CO 2 emissions, in metric tons CO 2 , for all above grade transmission

distribution transfer stations at your facility.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 199 of 227
(D) Annual CH 4 emissions, in metric tons CH 4 , for all above grade transmission

distribution tran sfer stations at your facility. (r) Equipment leaks by population count . If your facility is subject to the requirements of § 98 .233(r), then you must report the information specified in paragraph s (r)(1) through (r)(3) of this section , as applicable

. (1) You must indicate whether your facility contains 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 (r)(1)(v) of this section separately for each emis sion source type required to use Equation W

- 32A of this subpart that is located at your facility. Onshore petroleum and natural gas production facilities must report the information specified in paragraphs (r)(1)(i) through (r)(1)(v) of this section separa tely by component type, service type, and geographic location ( i.e. , Eastern U.S. or Western U.S.). (i) Emission source type. Onshore petroleum and natural gas production facilities must report the component type, service type and geographic location. (ii) Total number of the emission source type at the facility (“Count e ” in Equation W

- 32A of this subpart). (iii) Average estimated time that the emission source type was operational in the calendar year, in hours (“T e ” in Equation W

- 32A of this subpart). (iv) Annual CO 2 emissions, in metric tons CO 2 , for the emission source type. (v) Annual CH 4 emissions, in metric tons CH 4 , for the emission source type. (2) Natural gas distribution facilities must also report the information specified in paragraphs ( r )(2)(i) through ( r )(2)(v) of this s ection

. (i) Number of above grade transmission

- distribution transfer stations at the facility.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 200 of 227 (ii) Number of above grade metering

- regulating stations that are not transmission

distribution 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 transfer stations (“Count MR ” in Equation W

- 32B of this subpart). ( i v) Average estimated time that each meter/regulator run at above grade metering

regulating stations that are not above grade transmission

- distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T w,avg ” in Equation W

- 32B of this subpart). (v) If your facility has above grade metering

- regulating stations that are not above grade transmission

- distribution transfer stations and your facility also has above grade transmission

distribution transfer stations , you must also report: ( A ) Annual CO 2 emissions, in metric tons CO 2 , from above grade metering

- regulating stations that are not above grade transmission

- distribution transfer stations. ( B ) Annual CH 4 emissions, in metric tons CH 4 , from above grade metering regulating stations that are not abo ve grade transmission

- distribution transfer stations. (3) Onshore petroleum and natural gas production facilities must also report the information specified in paragraphs (r)(3)(i) and (r)(3)(ii) of this section. (i) Calculation method used. (ii) Onshore petroleum and natural gas production facilities must report the information specified in paragraphs ( r )(3)(ii)(A) and ( r )(3)( ii )(B) of this section, for each major equipment type, production type ( i.e. , natural gas or crude oil), and geographic location combination in Tables W

- 1B and W

- 1C of this subpart.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 201 of 227
(A) An indication of whether the facility contains the major equipment type. (B) If the facility does contain the equipment type, the count of the major equipment type. (s) Offshore petroleum and natural gas production . You must report the information specified in paragraphs (s)(1) through (s)(3) of this section for each emission source type listed in the most recent BOEMRE study. (1) Annual CO 2 emissions, in metric tons CO 2 . (2) Annual CH 4 emissions, in metric tons CH 4 . (3) Annual N 2 O emissions, in metric tons N 2 O. (t) [Reserved] (u) [Reserved] (v) [Reserved] (w) EOR injection pumps . You must indicate whether CO 2 EOR injection was used at
your facility during the calendar year and if any EOR injection pu mp blowdowns occurred during the year. If any EOR injection pump blowdowns occurred during the calendar year, then you must report the information specified in paragraphs (w)(1) through (w)(8) of this section for each EOR injection pump system. (1) Sub

- bas in ID. (2) EOR injection pump system identifier. (3) Pump capacity, in barrels per day. (4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“V v ” in Equation W

- 37 of this subpart). (5) Number of blowdowns for the EOR injection p ump system in the calendar year.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 202 of 227 (6) Density of critical phase EOR injection gas, in kilograms per cubic foot (“ R c ” in Equation W

- 37 of this subpart). (7) Mass fraction of CO 2 in critical phase EOR injection gas (“GHG CO2 ” in Equation W

37 of this subpart). (8) Annual CO 2 emissions, in metric tons CO 2 , from EOR injection pump system blowdowns. (x) EOR hydrocarbon liquids . You must indicate whether hydrocarbon liquids were produced through EOR operations. If hydrocarbon liquids were produced through EOR
opera tions, you must report the information specified in paragraphs (x)(1) through (x)(4) of this section for each sub

- basin category with EOR operations. (1) Sub

- basin ID. (2) Total volume of hydrocarbon liquids produced through EOR operations in the calendar year, in barrels (“V hl ” in Equation W

- 38 of this subpart). (3) 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). (4) Annual CO 2 emissio ns, in metric tons CO 2 , from CO 2 retained in hydrocarbon liquids produced through EOR operations downstream of the storage tank (“Mass CO2 ” in Equation W

- 38 of this subpart). (y) [Reserved] (z) Combustion equipment at onshore petroleum and natural gas production facilities and natural gas distribution facilities . If your facility is required by § 98 .232(c)(22) or (i)(7) to report emissions from combustion equipment, then you must indicate whether your facility has any combustion units subject to reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 203 of 227

section. If your facility contains any combustion units subject to reporting according to paragraphs (a)(1)(xvii) or (a)(8)( i ) of this section , then you must report the information specified in paragraphs (z)(1) and (z)(2) of this section, as applicable. (1) Indicate whether the combustion units include : external fuel combustion units with a rated heat capacity less than or equal to 5 million B tu 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 ca pacity less than or equal to 5 million Btu per hour or internal fuel combustion units that are not compressor

- drivers, with a rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 horsepower), then you must report the i nformation specified in paragraphs (z)(1)(i) and (z)(1)(ii) of this section for each unit type. (i) The type of combustion unit. (ii) The total number of combustion units. (2) Indicate whether the combustion units include: external fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not
compressor - drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or, internal fuel combusti on units of any heat capacity that are
compressor - drivers. If your facility contains: external fuel combustion units with a rated heat capacity greater than 5 mmBtu/hr; internal fuel combustion units that are not compressor

- drivers, with a rated heat capac ity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of any heat capacity that are compressor

- drivers, then you must report the information specified in paragraphs (z)(2)(i) through (z)(2)(vi) for each combustion unit type and fuel type combination.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 204 of 227 (i) The type of combustion unit. (ii) Th e type of fuel combusted. (iii) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, gallons, or tons. (iv) Annual CO 2 emissions , in metric tons CO 2 , calculated according to § 98 .233(z)(1) and (z)(2). (v) Annual CH 4 emissions, in metric tons CH 4 , calculated according to § 98 .233(z)(1) and (z)(2). (vi) Annual N 2 O emissions, in metric tons N 2 O, calculated according to § 98 .233(z)(1) and (z)(2). (aa) Each facility must report the information specified in paragraphs (aa)(1) through (aa)(9) of this section, for each applicable industry segment, by using best available data. If a quantity required to be reported is zero, you must report zero as the value. (1) For onshore petroleum and natural gas production, report the data specified in paragraphs (aa)(1)(i) and (aa)(1)(ii) of this section. (i) Report the information specified in paragraphs (aa)(1)(i)(A) through (aa)(1)(i)( C ) of this sect ion for the basin as a whole. (A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not include gas inject ed back into reservoirs or shrinkage resulting from lease condensate production. (B) The quantity of gas produced in the calendar year for sales, in thousand standard cubic feet.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 205 of 227 (C) The quantity of crude oil and condensate produced in the calendar year fo r sales, in barrels. (ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (aa)(1)(ii)(M) of this section for each unique sub

- basin category. (A) State. (B) County. (C) Formation type. (D) The number of producing wells at the end of th e calendar year (exclude only those wells permanently taken out of production, i.e. , plugged and abandoned)

. (E) The number of producing wells acquired during the calendar year. (F) The number of producing wells divested during the calendar year. (G) The number of wells completed during the calendar year. (H) The number of wells permanently taken out of production ( i.e. , plugged and abandoned) during the calendar year. (I) Average mole fraction of CH 4 in produced gas. (J) Average mole fraction of CO 2 in produced gas. (K) If an oil sub

- basin, report the average GOR of all wells, in thousand standard cubic feet per barrel. (L) If an oil sub

- basin, report the average API gravity of all wells. (M) If an oil sub

- basin, report average low pressure separator pressure , in pounds per
square inch gauge. (2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) and (aa)(2)(ii) of this section.

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(i) The total quantity of gas handled at the offshore platform in the calendar year, in thous and standard cubic feet , including production volumes and volumes transferred via pipeline from another location. (ii) The total quantity of oil and condensate handled at the offshore platform in the calendar year, in barrels , including production volumes and volumes transferred via pipeline from another location. (3) For natural gas processing, report the information specified in paragraphs (aa)(3)(i) through (aa)(3)(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 leaving the gas processing plant in the calendar year, in thousand standard cubic feet. (iii) The cumulative quantity of all NGLs (bulk and fractionated) r eceived at the gas processing plant in the calendar year, in barrels. (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 NGLs. (4) For natural gas transmission compression, report the quantity specified in paragraphs (aa)(4)(i) through (aa)(4) (v) of this section. (i) The quantity of gas transported through the compressor station in the calendar year, in thousand standard cubic feet.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 207 of 2 27 (ii) Number of compressors. (iii) Total compressor power rating of all compressors combined, in horsepower. (iv) Average upstream pipeline pressure, in pounds per square inch gauge. (v) Average downstream pipeline pressure, in pounds per square inch gauge. (5) For underground natural gas storage, report the quantities specified in paragraphs (aa)(5)(i) through (aa)(5 )(iii) of this section. (i) The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet. (ii) The quantity of gas withdrawn from storage in the calendar year, in thousand standard cubic feet. (iii) Total storage capacity , in thousand standard cubic feet. (6) For LNG import equipment, report the quantity of LNG imported in the calendar year, in thousand standard cubic feet. (7) For LNG export equipment, report the quantity of LNG exported in the calendar year, in thousand standard cubic feet. (8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (aa)(8)(iii) of this section. (i) The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet. (ii) The quantity of LNG withdrawn fr om storage in the calendar year , in thousand standard cubic feet. (iii) Total storage capacity, in thousand standard cubic feet.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 208 of 227 (9) For natural gas distribution, report the quantities specified in paragraphs (aa)(9)(i) through (aa)(9)(vii) of this section. (i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report. (ii) T he 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

- system storage in the calendar year, in thousand standard cubic feet. (iv) The quantity of natu ral gas delivered to end users, in thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for. (v) The quantity of natural gas transferred to third parties such as other LDCs or pipelines, in thousand sta ndard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for. (vi) The quantity of natural gas consumed by the LDC for operational purposes, in thousand standard cubic feet. (vii) The estimated quantity of gas stolen i n the calendar year, in thousand standard cubic feet. (bb) For any missing data procedures used, report the information in § 98.3( c )( 8 ) except as provided in paragraphs (bb) ( 1 ) and (bb) ( 2 ) of this section. ( 1 ) For quarterly measurements, report the total number of quarters that a missing data procedure was used for each data element rather than the total number of hours.

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( 2 ) For annual or biannual (once every two year s ) measurements, you do not need to report the number of hours that a missing data procedure was used for each data element

. (cc) If you elect to delay reporting the information in paragraph (g)(5)(i), (g)(5)(ii), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), (l)(4)(iii), (m)(5), or (m)(6) of thi s section, you must report the information 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), must be completed by April 1, 2011. In addition to the information required by § 98.3(g), you must retain the following records: (a) Dates on which measurements were conducted. (b) Results of all emissions detected and measurements. (c) Calibration reports for detection and measurement instruments used. (d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions. (e) The records required under § 98.3(g)(2)(i) shall include an explanation of how
company records, engineering estimation, or best available information are used to calculate each applicable parameter under this subpart. (f) For each time a missing data procedure was used , keep a record listing the emission source type, a description of the cir cumstance that resulted in the need to use missing data procedures, the missing data provisions in § 98. 2 3 5 that apply, the calculation or analysis used to develop the substitute value , and the substitute value

. § 98.238 Definitions

.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 210 of 227 Except as provided in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Acid gas means hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) contaminants that are separated from sour natural gas by an acid gas removal unit. Acid gas removal unit (AGR) means a process unit that separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid or solid absorbents or membrane separators. Acid gas removal vent emissions mean the acid gas separated from the acid gas absorbing medium ( e.g., an amine solution) and released with methane and other light hydrocarbons to the atmosphere or a flare. Associated gas venting or flaring means the venting or flaring of natural gas which originates at wellheads t hat also produce hydrocarbon liquids and occurs either in a discrete gaseous phase at the wellhead or is released from the liquid hydrocarbon phase by separation. This does not include venting or flaring resulting from activities that are reported elsewhere, including tank venting , well completions, and well workovers. Associated with a single well

- pad means associated with the hydrocarbon stream as produced from one or more wells located on that single well

- pad. The ass ociation ends where the stream from a single well

- pad is combined with streams from one or more additional single well

pads, where the point of combination is located off that single well

- pad. Onshore production storage tanks on or associated with a single well

- pad are considered a part of the onshore production facility. Basin means geologic provinces as defined by the American Association of Petroleum Geologists (AAPG) Geologic Note: AAPG

- CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75,

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 211 of 227 Number 10 (October 1991) (incorporated by reference, see § 98.7) and the Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Sta tistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see § 98.7). Component means each metal to metal joint or seal of non

- welded connection separated by a compression gasket, screwed thread (with or without thread sealing com pound), metal to metal compression, or fluid barrier through which natural gas or liquid can escape to the atmosphere. Compressor means any machine for raising the pressure of a natural gas or CO 2 by drawing in low pressure natural gas or CO 2 and dischargi ng significantly higher pressure natural gas or CO 2. Compressor mode means the operational and pressurized status of a compressor. For a centrifugal compressor, “m ode” refers to either operating

- mode or not

- operating

- depressurized

mode . For a reciprocating compressor, “mo de” refers to either: operating

- mode , standby

pressurized

- mode , or not

- operating

- depressurized

- mode

. Compressor source means the source of certain venting or leaking emissions from a centrifugal or reciprocating compressor. For centrifugal compressors, “source” refers to blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind flanges , and wet seal oil degassing vents. For reciprocating compressors, “source” refers to blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind flanges, and rod packing emissions

.

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Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, separated fr om 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 determine the boundary o f a field or producing reservoir. Distribution pipeline means a pipeline that is designated as such by the Pipeline and Hazardous Material Safety Administration (PHMSA) 49 CFR 192.3. Engineering estimation, for purposes of subpart W, means an estimate of emissions based on engineering principles applied to mea sured and/or approximated physical parameters such as dimensions of containment, actual pressures, actual temperatures, and compositions. Enhanced oil recovery (EOR) means the use of certain methods such as water flooding or gas injection into existing wel ls to increase the recovery of crude oil from a reservoir. In the context of this subpart, EOR applies to injection of critical phase or immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil. Equipment leak means those emissio ns which could not reasonably pass through a stack, chimney, vent, or other functionally

- equivalent opening. Equipment leak detection means the process of identifying emissions from equipment, components, and other point sources. External combustion means fired combustion in which the flame and products of combustion are separated from contact with the process fluid to which the energy is delivered. Process fluids may be air, hot water, or hydrocarbons. External combustion equipment may include fired heater s, industrial boilers, and commercial and domestic combustion units.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 213 of 227 Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements means the collection of all distribution pi pelines 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 municipally

- owned distribution system. Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements means the collection of all distribution pipelines and metering

- regulating stations that a re 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 municipally

- owned distribution system. Facility with respect to onshore petroleum and natural gas production for purposes of reporting under this subpart and for the corresponding subpart A requirements means all petroleum or natural gas equipment on a single well

- pad or associated with a single well

- pad and
CO 2 E OR op erations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petroleum and natural gas production owner or operator and that are located in a single hydrocarbon basin as defined in § 98.238. Wh ere a person or entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility.
Farm Taps are pressure regulation stations that deliver gas directly from transmission pipelines to generally rural customers. In some cases a nearby LDC may handle the billing of the gas to the customer(s).

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 214 of 227

Field means oil and gas fields identified in the Unit ed States as defined by the Energy Information Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see § 98.7). Flare, for the purposes of subpart W, means a combustion device, whether at ground level or ele vated, that uses an open or closed flame to combust waste gases without energy recovery. Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole basis, that is combusted at the flare burner tip. Flare stack emissions means CO 2 and N 2 O from partial combustion of hydrocarbon gas sent to a flare plus CH 4 emissions resulting from the incomplete combustion of hydrocarbon gas in flares. Forced extraction of natural gas liquids means removal of ethane or higher carbon number hydrocar bons existing in the vapor phase in natural gas, by removing ethane or heavier hydrocarbons derived from natural gas into natural gas liquids by means of a forced extraction process. Forced extraction processes include but are not limited to refrigeration, absorption (lean oil), cryogenic expander, and combinations of these processes. Forced extraction does not include in and of itself; natural gas dehydration, or the collection or gravity separation of water or hydrocarbon liquids from natural gas at ambie nt temperature or heated above ambient temperatures, or the condensation of water or hydrocarbon liquids through passive reduction in pressure or temperature, or portable dewpoint suppression skids. Horizontal well means a well bore that has a planned devi ation from primarily vertical to a primarily horizontal inclination or declination tracking in parallel with and through the target formation.

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Internal combustion means the combustion of a fuel that occurs with an oxidizer (usually air) in a combustion cha mber. In an internal combustion engine the expansion of the high

temperature and

- pressure gases produced by combustion applies direct force to a component of the engine, such as pistons, turbine blades, or a nozzle. This force moves the component over a d istance, generating useful mechanical energy. Internal combustion equipment may include gasoline and diesel industrial engines, natural gas

- fired reciprocating engines, and gas turbines. Liquefied natural gas (LNG) means natural gas (primarily methane) tha t has been liquefied by reducing its temperature to

- 260 degrees Fahrenheit at atmospheric pressure. LNG boil

- off gas means natural gas in the gaseous phase that vents from LNG storage tanks due to ambient heat leakage through the tank insulation and heat energy dissipated in the LNG by internal pumps. Manifolded compressor source means a compressor source (as defined in this section) that is manifolded to a common vent that routes gas from multiple compressors. Manifolded group of compressor sources means a collection of any combination of manifolded compressor sources (as defined in this section) that are manifolded to a common
vent. Meter/regulator run means a series of components used in regulating pressure or metering natural gas flow , or both , in the natural gas distribution industry segment. At least one meter, at least on e regulator, or any combination of both on a single run of piping is considered one meter/regulator run

. Metering

- regulating station means a station that meters the flowrate, regulates the pressure, or both, of natural gas in a natural gas distribution facility. This does not include
customer meters , customer regulators, or farm taps.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 216 of 227 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 lim ited to, methane, heavier hydrocarbons and carbon dioxide. Natural gas may be field quality, pipeline quality, or process gas. Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act. Onshore petroleum and natural gas production owner o r operator means the person or entity who holds the permit to operate petroleum and natural gas wells on the drilling permit or an operating permit where no drilling permit is issued, which operates an onshore petroleum and/or natural gas production facili ty (as described in § 98.230(a)(2). Where petroleum and natural gas wells operate without a drilling or operating permit, the person or entity that pays the State or Federal business income taxes is considered the owner or operator. Operating pressure mean s the containment pressure that 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 ps ig and less than or equal to 60 psig; greater than 60 psig and less than or equal to 110 psig; greater than 110 psig and less than or equal to 200 psig; and greater than 200 psig. The pressure in the context of pressure groups is either the well shut

- in pr essure; 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 each well in the sub

- basin.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 217 of 227
Pump means a device used to raise pressure, drive, or increase flow of liquid s treams in closed or open conduits. Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon dioxide containing light liquids from escaping the inside of a pump case to the atmosphere. Pump seal emissions means hydrocarbon gas rele ased from the seal face between the pump internal chamber and the atmosphere. Reservoir means a porous and permeable underground natural formation containing significant quantities of hydrocarbon liquids and/or gases. Reduced emissions completion means a well completion 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 collection system, re

- injected into the well or anothe r 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 reduced emissions completion may occur. Reduced emissions workover means a well workover with 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, re

injected into the well or another well, used as an on

- site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with de minimis direct venting to the atmosphere. Short periods of flaring during a reduced emission s workover may occur. Residue Gas and Residue Gas Compression mean, respectively, production lease natural gas from which gas liquid products and, in some cases, non

- hydrocarbon components have been extracted such that it meets the specifications set by a pipeline transmission company, and/or a

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 218 of 227 distribution company; and the compressors operated by the processing facility, whether inside the processing facility boundary fence or outside the fence

- line, that deliver the residue gas from the processing facilit y to a transmission pipeline. Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase. Sub

- basin category, for onshore natural gas production, means a subdivision of a basin into the unique combination of wells with the surface coordinates within the boundaries of an individual county and subsurface completion in one or more of each of the following five formation types: Oil, high permeability gas, shale gas, coal seam, or other tight gas re servoir 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. Permeabilit y for a reservoir type shall be determined by engineering estimate. Wells that produce only from high permeability gas, shale gas, coal seam, or other tight gas reservoir rock are considered gas wells; gas wells producing from more than one of these formation types shall be classified into only one type based on the formation with the most contribution to production as determined by engineering knowledge. All well s that produce hydrocarbon liquids (with or without gas) and do not meet the definition of a gas well in this sub

- basin category definition are considered to be in the oil formation. All emission sources that handle condensate from gas wells in high permea bility 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.

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Transmission

- distribution (T

- D) transfer station means a metering

- regulating station where a loca l distribution company takes part or all of the natural gas from a transmission pipeline and puts it into a distribution pipeline. Transmission pipeline means a Federal Energy Regulatory Commission rate

- regulated Interstate pipeline, a state rate

- regulated Intrastate pipeline, or a pipeline that falls under the “Hinshaw Exemption” as referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717

- 717 (w)(1994). Tubing diameter groups are defined as follows: Outer diameter less than or equal to 1 inch; oute r diameter greater than 1 inch and less than 2.375 inch; and outer diameter greater than or equal to 2.375 inch. Tubing systems means piping equal to or less than one half inch diameter as per nominal pipe size. Turbine meter means a flow meter in which a 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. Vented emissions means intentional or designed releases of CH 4 or CO 2 con taining natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process designed flow to the atmosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas used to power equipment (suc h as pneumatic devices). Vertical well means a well bore that is primarily vertical but has some unintentional deviation or one or more intentional deviations to enter one or more subsurface targets that are off

- set horizontally from the surface location, intercepting the targets either vertically or at an angle.

This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 220 of 227 Well testing venting and flaring means venting and/or flaring of natural gas at the time the production rate of a well is determined for regulatory, commercial, or technical purposes. If well testi ng is conducted immediately after well completion or workover, then it is considered part of well completion or workover. Wildcat well means a well outside known fields or the first well drilled in an oil or gas field where no other oil and gas production exists.
Table W
- 1A of Subpart W of Part 98

— Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production Onshore petroleum and natural gas production Emission factor (scf/hour/component) Eastern U.S. Population Emission Factors

— All Components, Gas Service 1 Valve 0.027 Connector 0.003 Open

- ended Line 0.061 Pressure Relief Valve 0.040 Low Continuous Bleed Pneumatic Device Vents 2 1.39 High Continuous Bleed Pneumatic Device Vents 2 37.3 Intermittent Bleed Pneumatic Device Vents 2 13.5 Pneumatic Pumps 3 13.3 Population Emission Factors

— All Components, Light Crude Service 4 Valve 0.05 Flange 0.003 Connector 0.007 Open

- ended Line 0.05 Pump 0.01 Other 5 0.30 Population Emission Factors

— All Components, Heavy Crude Service 6 Valve 0.0005 Flange 0.0009 Connector (other) 0.0003
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Onshore petroleum and natural gas production Emission factor (scf/hour/component) Open

- ended Line 0.006 Other 5 0.003 Western U.S. Population Emission Factors

— All Components, Gas Service 1 Valve 0.121 Connector 0.017 Open

- ended Line 0.031 Pressure Relief Valve 0.193 Low Continuous Bleed Pneumatic Device Vents 2 1.39 High Continuous Bleed Pneumatic Device Vents 2 37.3 Intermittent Bleed Pneumatic Device Vents 2 13.5 Pneumatic Pumps 3 13.3 Population Emission Factors

— All Components, Light Crude Service 4 Valve 0.05 Flange 0.003 Connector (other) 0.007 Open

- ended Line 0.05 Pump 0.01 Other 5 0.30 Population Emission Factors

— All Components, Heavy Crude Service 6 Valve 0.0005 Flange 0.0009 Connector (other) 0.0003 Open

- ended Line 0.006 Other 5 0.003
1 For multi

- phase flow that includes gas, use the gas service emissions factors.
2 Emission Factor is in units of “scf/hour/device.”
3 Emission Factor is in units of “scf/hour/pump.”
4 Hydrocarbon liquids greater than or equal to 20°API are considered “light crude.”
5 “Others” categ ory includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents.
6 Hydrocarbon liquids less than 20°API are considered “heavy crude.”

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Table W
- 1B to Subpart W of Part 98

— Default Average Component Counts for Major Onshore Natural Gas Production Equipment Major equipment Valves Connectors Open
- ended lines Pressure relief valves Eastern U.S. Wellheads 8 38 0.5 0 Separators 1 6 0 0 Meters/piping 12 45 0 0 Compressors 12 57 0 0 In

- line heaters 14 65 2 1 Dehydrators 24 90 2 2 Western U.S. Wellheads 11 36 1 0 Separators 34 106 6 2 Meters/piping 14 51 1 1 Compressors 73 179 3 4 In

- line heaters 14 65 2 1 Dehydrators 24 90 2 2

Table W
- 1C to Subpart W of Part 98

— Default Average Component Counts For Major Crude Oil Production Equipment Major equipment Valves Flanges Connectors Open
- ended lines Other components Eastern U.S. Wellhead 5 10 4 0 1 Separator 6 12 10 0 0 Heater

- treater 8 12 20 0 0 Header 5 10 4 0 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

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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 Iowa Massachusetts Kansas Michigan Louisiana New Hampshire Minnesota New Jersey Mississippi New York Missouri North Carolina Montana Ohio Nebraska Pennsylvania Nevada Rhode Island New Mexico South Carolina North Dakota Tennessee Oklahoma Vermont Oregon Virginia South Dakota West Virginia Texas Wisconsin Utah Washington Wyoming
Table W
- 2 of Subpart W of Part 98

— Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Processing
Onshore natural gas processing plants Emission factor (scf/hour/component) Leaker Emission Factors

— Compressor Components, Gas Service
This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 224 of 227

Onshore natural gas processing plants Emission factor (scf/hour/component) 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 regulator valves.

Table W
- 3 of Subpart W of Part 98

— Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Transmission Compression Onshore natural gas transmission compression 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 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 This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 225 of 227

1 Valves include control valves, block valves and regulator valves. 2 Emission Factor is in units of “scf/hour/device.”
Table W
- 4 of Subpart W of Part 98

— Default Total Hydrocarbon Emission Factors for Underground Natural Gas Storage Underground natural gas storage Emission factor (scf/hour/component) Leaker Emission Factors

— Storage Station, Gas Service Valve 1 14.84 Connector 5.59 Open

- Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 Population Emission Factors

— Storage Wellheads, Gas Service Connector 0.01 Valve 0.1 Pressure Relief Valve 0.17 Open Ended Line 0.03 Population Emission Factors

— Other Components, Gas Service Low Continuous Bleed Pneumatic Device Vents 2 1.37 High Continuous Bleed Pneumatic Device Vents 2 18.20 Intermittent Bleed Pneumatic Device Vents 2 2.35
1 Valves include control valves, block valves and regulator valves. 2 Emission Factor is in units of “scf/hour/device.”
Table W
- 5 of Subpart W of Part 98

— Default Methane Emission Factors for Liquefied Natural Gas (LNG) Storage LNG storage Emission factor (scf/hour/compone nt) 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 equipment type other than connectors, pumps, or valves. This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 226 of 227

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 equ ipment Emission factor (scf/hour/component) Leaker Emission Factors

— LNG Terminals Components, LNG Service Valve 1.19 Pump Seal 4.00 Connector 0.34 Other 1 1.77 Population Emission Factors

— LNG Terminals Compressor, Gas Service Vapor Recovery Compressor 2 4.17
1 “Other” equipment type should be applied for any equipment type other than connectors, pumps, or valves. 2 Emission Factors is in units of “scf/hour/compressor.”
Table W
- 7 of Subpart W of Part 98

— Default Methane Emission Factors for Natural Gas Distribution
Natural gas distribution Emission factor (scf/hour/ component) Leaker Emission Factors

— Transmission
- Distribution Transfer Station 1 Components, Gas Service Connector 1.69 Block Valve 0.557 Control Valve 9.34 Pressure Relief Valve 0.27 Orifice Meter 0.212 Regulator 0.772 Open

- ended Line 26.131 Population Emission Factors

— Below Grade Metering
- Regulating station 1 Components, Gas Service 2 Below Grade M&R Station, Inlet Pressure > 300 psig 1.30 Below Grade M&R Station, Inlet Pressure 100 to 300 psig 0.20 Below Grade M&R Station, Inlet Pressure < 100 psig 0.10 Population Emission Factors

— Distribution Mains, Gas Service 3 Unprotected Steel 12.58 Protected Steel 0.35 Plastic 1.13 This document showing the final amendments to subparts A and W is provided for informational puroposes only. We have taken steps to ensure the accuracy of this version, but it is not the official version.Page 227 of 227

Natural gas distribution Emission factor (scf/hour/ component) 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.”

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