*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal Regulations is amended as follows: **PART 98 –**  **[AMENDED]** 1. The authority citation for part 98 continues to read as follows: **Authority:** 42 U.S.C. 7401
- 7671q. **Subpart W** 

**— [Amended]**  **-- P** **etroleum and Natural Gas Systems** Contents § 98.230 Definition of the source category. § 98.231 Reporting threshold. § 98.232 GHGs to report. § 98.233 Calculating GHG emission s. § 98.234 Monitoring and QA/QC requirements. § 98.235 Procedures for estimating missing data. § 98.236 Data reporting requirements. § 98.237 Records that must be retained. § 98.238 Definitions. Table W
- 1A of Subpart W of Part 98

—Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production Table W
- 1B to Subpart W of Part 98

—Default Average Component Counts for Major Onshore Natural Gas Production Equipment Table W
- 1C to Subpart W of Part 98

—Default Average Component Counts For Major Crude Oil Production Equipment Table W
- 1D of Subpart W of Part 98

—Designation Of Eastern And Western U.S. Table W
- 2 of Subpart W of Part 98

—Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Processing Table W
- 3 of Subpart W of Part 98

—Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Transmission Compression Table W
- 4 of Subpart W of Part 98

—Default Total Hydrocarbon Emission Factors for Underground Natural Gas Storage Table W
- 5 of Subpart W of Part 98

—Default Methan e Emission Factors for Liquefied Natural Gas (LNG) Storage Table W
- 6 of Subpart W of Part 98

—Default Methane Emission Factors for LNG Import and Export Equipment Table W
- 7 of Subpart W of Part 98

—Default Methane Emission Factors for Natural Gas Distributio n*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 2 of 151 § 98.230 Definition of the source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 temporar ily or permanently to offshore submerged lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore. In addition, offshore production inc ludes secondary platform structures connected to the platform structure via walkways, storage tanks associated with the platform structure and floating production and storage offloading equipment (FPSO). This source category does not include reporting of emissions from offshore drilling and exploration that is not conducted on production platforms. (2) Onshore petroleum and natural gas production . Onshore petroleum and natural gas production means all equipment on a single well
-pad or associated with a sing le well
-pad (including but not limited to compressors, generators, dehydrators, storage vessels, and portable non
- self
-propelled equipment which includes well drilling and completion equipment, workover equipment, gravity separation equipment, auxiliary no n transportation
- related equipment, and leased, rented or*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 3 of 151 contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate). This equipment also include s associated storage or measurement vessels and all enhanced 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. (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 a ll residue gas compression equipment owned or operated by the natural gas processing plant. This industry segment includes processing plants that fractionate gas liquids, and processing plants that do not fractionate gas liquids but have an annual average throughput of 25 MMscf per day or greater.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 4 of 151 (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 p lants, 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, an d tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compression that is part of onshore natural gas processing plants are included in the onshore natural gas processing segment and are excluded from this segment. (5) Underground n atural 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 balanci ng (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 connecte d to the compression units located at the facility that inject and recover natural gas into and from the underground reservoirs.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 5 of 151 (6) Liquefied natural gas (LNG) storage . LNG storage means onshore LNG storage vessels located above ground, equipment for liqu efying natural gas, compressors to capture and 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 equipmen t that receives imported LNG via ocean transport, stores LNG, re
- gasifies LNG, and delivers re
- gasified natural gas to a natural gas transmission or distribution system. LNG export equipment means all onshore or offshore equipment that receives natural gas , liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to any location, including locations in the United States. (8) Natural gas distribution . Natural gas distribution means the distribution pipelines and metering and regulati ng equipment at 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 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 directly to*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 6 of 151 major industrial users and farm taps upstream of the local distribution company inlet. (b) [Reserved] § 98 . 231 Reporting threshold . (a) You must report GHG emissions under this subpart if your facility contains petroleum and natural gas systems and the facility meets the requirements of § 98.2(a)(2). Facilities must report emissio ns 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 e quivalent or more per year. Facilities must report emissions from the natural gas distribut ion industry segment only if emission sources specified in paragraph § 98.232(i) emit 25,000 metric tons of CO 2 e quivalent or more per year. (b) For applying the threshold defined in § 98.2(a)(2), natural gas processing facilities must also include owned or operated residue gas compression equipment. § 98 . 232 GHGs to report . (a) You must report CO 2 , CH 4 , and N 2 O emissions from each industry segment specified in paragraph (b) through (i) of this section, CO 2 , CH 4 , and N 2 O emissions from each flare as specified in paragraph (b) through (i) of this section, and stationary and*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 7 of 151 portable combustion emissions as applicable as specified in paragraph (k) of this section. (b) For offshore petroleum and natural gas production, repor t CO 2, CH 4, and N 2 O emissions from equipment leaks, vented emission, and flare emission source types as identified in the data collection and emissions estimation study conducted by BOEMRE in compliance with 30 CFR 250.302 through 304. Offshore 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 associated with a single well
-pad: (1) Natural gas pn eumatic device venting. (2) [Reserved] (3) Natural gas driven pneumatic pump venting. (4) Well venting for liquids unloading. (5) Gas well venting during well completions without hydraulic fracturing. (6) Gas well venting during well completions with hydraulic fracturing. (7) Gas well venting during well workovers without hydraulic fracturing.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 8 of 151 (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 injection pump blowdown. (17) Acid gas removal ven ts. (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 instrumen ts, 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 9 of 151 stationary or portable fuel combustion equipment that cannot move on roadways under its own power and drive train, and that is located at an onshore petroleum and natural gas production facility as defined in § 98.238. Stationary or portable equipment are the following equipment, which are integral to the ext raction, processing, or movement of oil or natural gas: well drilling and completion equipment, workover equipment, natural gas dehydrators, natural gas compressors, electrical generators, steam boilers, and process heaters. (d) For onshore natural gas pro cessing, 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 emissi ons. (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 emissions from the following sources: (1) Reciprocating compressor rod pa cking venting. (2) Centrifugal compressor venting.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 10 of 151 (3) Transmission storage tanks. (4) Blowdown vent stacks. (5) Natural gas pneumatic device venting. (6) [Reserved] (7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. (f) For underground natural gas storage, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compressor rod packing venting. (2) Centrifugal compressor venting. (3) Natural gas pneumatic device venting. (4) [Reserved] (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 compres sor venting. (3) Equipment leaks from valves; pump seals; connectors; vapor recovery compressors, and other equipment leak sources. (h) LNG import and export equipment, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Reciprocating compre ssor rod packing venting.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 11 of 151 (2) Centrifugal compressor venting. (3) Blowdown vent stacks. (4) Equipment leaks from valves, pump seals, connectors, vapor recovery compressors, and other equipment leak sources. (i) For natural gas distribution, report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Meters, regulators, and associated equipment at above grade transmission
- distribution transfer stations, including equipment leaks from connectors, block valves, control valves, pressure relief valves, or ifice meters, regulators, and open ended lines. (2) Equipment leaks from vaults at below grade transmission
- distribution transfer stations. (3) Meters, regulators, and associated equipment at above grade metering
- regulating station. (4) Equipment leaks from vaults at below grade metering
regulating stations. (5) Pipeline main equipment leaks. (6) Service line equipment leaks. (7) Report under subpart W of this part the emissions of CO 2 , CH 4 , and N 2 O emissions from stationary fuel combustion sources followin g the methods in § 98.233(z) (j) [Reserved]*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 12 of 151 (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 must 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 . You must calculate and report the annual GHG emissions as prescribed in this section. For actual conditions, 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 emissions from continuous high bleed, continuous low bleed,*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 13 of 151 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 * * * *

, 

###  (Eq. W
- 1)
Where:
Mass t,i = Annual total mass GHG emissions in metric tons CO 2 e

per year from a natural gas pneumatic device vent of type “t”, for GHG i . Count t = Total number of natural gas pneumatic devices of

type “t” (continuous high bleed, continuous low bleed, intermittent bleed) as determined in paragraph (a)(1), (a)(2), and (a)(3) of this se ction. EF t = Population emission factors for natural gas

pneumatic device venting 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 ga s storage facilities, respectively. 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 and underground natural gas storage, GHG i equals 0.975 for CH 4 and 1.1 × 10 −2 for CO 2 . Conv i = Conversion from standard cubic feet to met ric 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. Default is 8760 hours. (1) For onshore petroleum and natural gas production, provide the total number of continuous high bleed, continuous*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 14 of 151 low bleed, or intermittent bleed natural gas pneumatic devices of each type as follows: (i) In the first calendar year, for the total number of each type, you may count the total of each type, or count any percentage number of each type plus an engineering estimate based on best available data of the number not counted. (ii) In the second consecutive year, for the total number of each type, you may count the total of each type, or count any percentage number of each type plus an engineering estimate based on best available data of the number not counted. (iii) In the third consecutive calendar year, complete the count of all pneumatic devices, including any changes to equipment counted in prior years. (iv) Fo r 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 must be counted in the first year and updated every calendar year.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 15 of 151 (3) For all industry segments, determine the type of pneumatic dev ice using engineering estimates based on best available information. (b) [Reserved] (c) Natural gas driven pneumatic pump venting . Calculate CH 4 and CO 2 emissions from natural gas driven pneumatic pump venting using Equation W
- 2 of this section. Natural ga s driven pneumatic pumps covered in paragraph (e) of this section do not have to report emissions under paragraph (c) of this section. T Conv GHG EF Count Mass i i i * * * *  (Eq. W
- 2)
Where:
Mass i = Annual total mass GHG emissions in metric tons CO 2 e

per year from all natural gas pneumatic pump venting, for GHG i . Count = Total number of natural gas pneumatic pumps. EF = Population emissions factors for natural gas

pneumatic pump venting listed in Tables W
- 1A of this subpart for onshore petroleum and natural gas producti on. GHG i = Concentration of GHG i , CH 4 , or CO 2 , in produced

natural gas as defined in paragraph (u)(2)(i) of this section. Conv i = Conversion from standard cubic feet to metric tons

CO 2 e ; 0.0004 79 for CH 4 , and 0.00005262 for CO 2 . T = Average estimated number of hours in the operating

year the pumps were operational. Default is 8760 hours. (d) Acid gas removal (AGR) vents . For AGR vent (including processes such as amine, membrane, molecular sieve or other*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 16 of 151 absorbents and adsorbents), calculate emissions for CO 2 only (not CH 4 ) vented directly to the atmosphere or through a flare, engine ( e.g., permeate from a membrane or de
- adsorbed gas from a pressure swing adsorber used as fuel supplement), or sulfur recovery plant using any of the calculation methodologie s described in paragraph (d) of this section, as applicable. (1) Calculation Methodology 1 . If you operate and maintain a CEMS that has both a CO 2 concentration monitor and volumetric flow rate monitor, you must calculate CO 2 emissions under this subpart b y following the Tier 4 Calculation Methodology 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 Methodology in subpart C of this part (General Stationary Fuel Combustion). The calculation and reporting of CH 4 and N 2 O emissions is not required as part of the Tier 4 requirements for AGRs.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 17 of 151 (2) Calcula tion Methodology 2 . If 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.
Ea,CO2 = V S * Vol CO2 (Eq. W
- 3)
Where:
E a,CO2 = Annual volumetric CO 2 emissions at actual

conditions, in cubic feet per year. VS = 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 fraction of CO 2 content in vent gas out of

the AGR unit as determined in (d)(6) of this section. (3) Calculation Methodology 3 . If 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 f low rate is known, use Equation W
- 4B.      

    O O

I in CO a Vol

Vol Vol V E 1 2 , (Eq. W
- 4A)*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 18 of 151

     

    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. Vin = Total annual volume of natural gas flow into the

AGR unit in cubic feet per year at actual condition as determined using methods specified in paragraph (d)(5) of this section. Vout = Total annual volume of natural gas flow out of the

AGR unit in cubic feet per year at actual condition as determined u sing methods specified in paragraph (d)(5) of this section. Vol I = Volume fraction of CO 2 content in natural gas into

the AGR unit as determined in paragraph (d)(7) of this section. Vol o = Volume fraction of CO 2 content in natural gas out of

the AGR unit a s determined in paragraph (d)(8) of this section. (4) Calculation Methodology 4 . If CEMS or a vent meter is not installed, you may calculate emissions using any standard simulation software packages, such as AspenTech HYSYS ® and API 4679 AMINECalc, that uses the Peng
- Robinson equation of state, and speciates CO 2 emissions. A minimum of the following determined for typical operating conditions over the calendar year by engineering estimate and process knowledge based on best available data must be used to characterize emissions: (i) Natural gas feed temperature, pressure, and flow rate. (ii) Acid gas content of feed natural gas.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 19 of 151 (iii) Acid gas content of outlet natural gas. (iv) Unit operating hours, excluding downtime for mai ntenance or standby. (v) Exit temperature of natural gas. (vi) Solvent pressure, temperature, circulation rate, and weight. (5) Record the gas flow rate of the inlet and outlet 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 continuous gas analyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream to determine Vol CO2 according to methods set forth in § 98.234(b). (7) If a continuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be
use d. If continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas stream to determine Vol I according to methods set forth in § 98.234(b).*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 20 of 151 (8) Determine volume fraction of CO 2 content in natural gas out of the AGR unit using one of the methods specified in paragraph (d)(8) 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 anal yzer is not available, you may install a continuous gas analyzer. (ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet gas stream to determine Vol O according to methods set forth in § 98.234(b). (iii) Use sales line quality specification for CO 2 in natural gas. (9) Calculate CO 2 volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (10) Mass CO 2 emissions shall be calculated from volumetric CO 2 emissions using calculations in paragraph (v) of this section. (11) Determine if emissions from the AGR unit are recovered and transferred outside the facility. Adjust the emission estimated in paragraphs (d)(1) through (d)(10) of this section downward by the magni tude of emission recovered and transferred outside the facility.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 21 of 151 (e) Dehydrator vents . For dehydrator vents, calculate annual CH 4 , CO 2 and N 2 O emissions using any of the calculation methodologies described in paragraph (e) of this section. (1) Calculation Methodology 1 . Calculate annual mass emissions from dehydrator vents with annual average daily throughput greater than or equal to 0.4 million standard cubic feet per day using a software program, such as AspenTech HYSYS ® or GRI
- GLYCalc, 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 following parameters determined by engineering estimate based on best available data must be used to characterize emissions from dehydrators: (i) Feed natural gas flow rate. (ii) Feed natural gas water content. (iii) Outlet natural gas water content. (iv) Absorbent circulation pump type (natural gas pneumatic/air pneumatic/electric). (v) Absorbent circulation rate. (vi) Absorbent type: including triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG).*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 22 of 151 (vii) Use of st ripping 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 one of the methods described under paragraph (e)(1)(xi) of this section. (A) Use the wet natural gas composition as defined in paragraph (u)(2)(i) or (u)(2)(ii) of this section. (B) If wet natural gas composition cannot be determined using paragraph (u)(2)(i) or (u)(2)(ii) of this sec tion, select a representative analysis. (C) You may use an appropriate standard method published by
a consensus -based standards organization if such a method exists or you may use an industry standard practice as specified in § 98.234(b) to sample and analy ze wet natural gas composition. (D) If only composition data for dry natural gas is available, assume the wet natural gas is saturated. (2) Calculation Methodology 2 . Calculate annual CH 4 and CO 2
emissions from glycol dehydrators with annual average daily throughput less than 0.4 million standard cubic feet per day using Equation W
- 5 of this section:*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 23 of 151



### 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 throughput

less than 0.4 million standard cubic feet per day. 1000 = Conversion of EF i in thousand standard cubic feet to

standard cubic feet. (3) Determine if dehydrator unit has vapor recovery. Adjust the emissions estimated in paragraphs (e)(1) or (e)(2) of this section downward by the magnitude of emissions captured. (4) Calculate annual emissions from 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 the calculation methodology of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas vent. (5) Dehydrators that use desiccant shall calculate emissions from the amount of gas vented from the vessel when it is depressurized for the desiccant refilling process using Equation W
- 6 of this section. Desiccant dehydrators covered in*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 24 of 151 (e)(5) of this section do not have to report emissions under (i) of this section.

Es,n = (H*D2 *P*P2 *%G*365days/yr) (Eq. W
- 6)

(4*P1 *T*1,000cf/Mcf*100) 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 = 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) For glycol dehydrators, both CH 4 and CO 2 mass emissions shall be calculated from volumetric GHG i emissions using calculations in paragraph (v) of this section. For dehydrators that use desiccant, both CH 4 and CO 2 volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calculations i n paragraphs (u) and (v) of this section. (f) Well venting for liquids unloadings . Calculate CO 2 and CH 4 emissions from well venting for liquids unloading using one*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 25 of 151 of the calculation methodologies described in paragraphs (f)(1), (f)(2) or (f)(3) of this s ection. (1) Calculation Methodology 1 . 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 catego ry), where gas wells are vented to the atmosphere to expel liquids accumulated in the tubing, a recording flow meter shall be installed on the vent line used to vent gas from the well (e.g., on the vent line off the wellhead separator or atmospheric storage tank) according to methods set forth in § 98.234(b). Calculate emissions from well venting for liquids unloading using Equation W
- 7 of this section. 

# 

  h

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

Where:
E a,n = Annual natural gas emissions for all wells of the

same tub ing diameter group and pressure group combination in a sub
-basin at actual conditions in cubic feet. h = Total number of wells of the same tubing diameter

group and pressure group combination in a sub
basin. p = Wells 1 through h of the same tubing diamete r 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 26 of 151 pressure group combination in a sub
-basin during the year. FR = Average flow rate in cubic fee t per hour for all

measured wells venting for the duration of the liquids unloading, under actual conditions as determined in paragraph (f)(1)(i) of this section. (i) Determine the well vent average flow rate as specified under paragraph (f)(1)(i) of this section for at least one well in a unique well tubing diameter group and pressure group combination in each sub
-basin category. (A) The average flow rate per hour of venting is calculated for each unique tubing diameter group and pressure group combination in each sub
-basin category by dividing the recorded total flow by the recorded time (in hours) for all measured liquid unloading events with venting to the atmosphere. (B) This average flow rate per hour is applied 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 new average flow rate is calculated every other calendar year for each reporting sub
-basin category starting the first calendar year of data collection. For a n ew producing sub
basin category, an average flow rate is calculated beginning in the first year of production. (ii) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 27 of 151 (2) Calculation Metho dology 2 . Calculate the total emissions for well venting for liquids unloading using Equation W- 8 of this section.



#      

   

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

q q p q p q p p p p n 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 at standard

conditions, in cubic feet/year. W = Total number of wells with well venting for liquids

unloading for each sub
-basin. 0.37×10 −3 = {3.14 (pi)/4}/{14.7*144} (psia converted to

pounds per square feet). CDp = Casing internal diameter for each well, p, in

inches. WDp = 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. SPp = 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 (ps ia); 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). Vp = Number of unloading events per year per well, p. SFRp = Average flow
- line rate of gas for well, p, at

standard conditions in cubic feet per hour. Use Equation W
- 33 to calculate the average flow
- line rate at standard conditions. HRp,q = Hours that each well, p, was left open to the

atmosphere during each unloading event, q. 1.0 = Hours for average well to blowdown casing volume at

shut
- in pressure.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 28 of 151 Z p,q = If HRp,q is less than 1.0 then Z p,q is equal to 0. If

HRp,q is greater than or equal to 1.0 then Z p,q is equal to 1. (3) Calculation Methodology 3 . Calculate emissions from well venting to the atmosphere for liquids unloading with plunger lift assist using Equation W
- 9 of this section.



#      

   

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

q q p q p q p p p p n 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 at standard

conditions, in cubic feet/year. W = Total number of wells with plunger lift assist and

well venting for liquids unloading for each sub
basin. 0.37×10 −3 = {3.14 (pi)/4}/{14.7*144} (psia converted to

pounds per square feet). TDp = Tubing internal diameter for each well, p, in

inches. WDp = Tubing depth to plunger bumper for each well, p, in

feet. SPp = Flow
- line pressure for each well, p, in pounds per

square inch absolute (psia), using engineering estimate based on best available data. Vp = Number of unloading events per year for each well ,

p. SFRp = Average flow
- line rate of gas for well, p, at

standard conditions in cubic feet per hour. Use Equation W
- 33 to calculate the average flow
- line rate at standard conditions. HRp,q = Hours that each well, p, was left open to the

atmosphere during each unloading event, q. 0.5 = Hours for average well to blowdown tubing volume at

flow
- line pressure.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 29 of 151 Z p,q = If HRp,q is less than 0.5 then Z p,q is equal to 0. If

HRp,q is greater than or equal to 0.5 then Z p,q is equal to 1. (i)
- (ii) [Reserved] (4) 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. (g) Gas well venting during completions and workovers from hydraulic fracturing . Calculate CH 4 , CO 2 and N 2 O annual emissions from gas well venting during completions involving hydraulic fracturing in wells and well workovers using Equation W
- 10A or Equation W
- 10B of this section. Equation W
- 10A applies to well venting when the backflow rate is measured or calcu lated, Equation W
- 10B applies when the backflow vent or flare volume is measured. Use Equation W
- 10A if the flow rate for backflow during well completions and workovers from hydraulic fracturing is known for the specified number of wells per paragraph (g)( 1) in a sub
-basin and well type (horizontal or vertical) combination. Use Equation W
- 10B if the flow volume for backflow during well completions and workovers from hydraulic fracturing is known for all wells in a sub
-basin and well type (horizontal or vert ical) combination. Both CH 4 and CO 2 volumetric and mass emissions shall be calculated from volumetric total gas*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 30 of 151 emissions using calculations in paragraphs (u) and (v) of this section. 

#  



 

    W
p p p p p n s SG EnF PR FRM T E 1 , (Eq. W- 10A)



#   

   W
p p

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

Where:
E s,n = Annual volumetric total gas emissions in 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 = Tota l number of wells completed or worked over

using hydraulic fracturing in a sub
-basin and well type (horizontal vs. vertical) combination. T p = Cumulative amount of time of backflow for the

completion or workover, in hours, for each well, p, in a sub
-basin and well type (horizontal vs. vertical) combination during the reporting year. FRMs = Ratio of flowback during well completions and

workovers from hydraulic fracturing to 30
- day production rate from Equation W
- 12. PRs,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. EnF s,p = Volume of CO 2 or N 2 injected gas in cubic feet at

standard conditions that was injected into the reservoir during an energized fracture job for each well p. If the fracture process did not inject gas into the reservoir, then EnF s,p is 0. If 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 31 of 151 injected into the well for clean
- up. If no gas was recovered, SG s,p is 0. FVs,p = Flow volume of each well (p) in standard cubic feet

measured using a recording flow mete r (digital or analog) on the vent line to measure flowback during the completion or workover according to methods set forth in § 98.234(b). (1) The average flow rate for flowback during well completions and workovers from hydraulic fracturing shall be determined using measurement(s) for Calculation Methodology 1 or calculation(s) for Calculation Methodology 2 described in this paragraph (g)(1) of this section. If Equation W
- 10A is used, the number of measurements or calculations shall be determined per sub
-b asin and well type (horizontal or vertical) as follows: at least one measurement or calculation for less than or equal to 25 completions or workovers; at least two measurements or calculations for 26 to 50 completions or workovers; at least three measureme nts 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 Me thodology 1 . When using Equation W
- 10A, for each measured well completion(s) in each gas producing sub
basin category and well type (horizontal or vertical) combination and for each measured well workover(s) in each gas producing sub
-basin category and wel l type (horizontal or*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 32 of 151 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) Calculation Metho dology 2 . When using Equation W
- 10A, for each calculated horizontal well completion and each calculated vertical well completion in each gas producing sub
basin category and for each calculated well horizontal workover and for each 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 forth in § 98.234(b) to calculate the well backflow during well completions and workover s 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 engineering estimate based on best available data along with Equation W
- 11C of this section t o determine whether the predominant flow is sonic or subsonic. If the value of R in Equation W
- 11C is greater than or equal to 2, then flow is sonic; otherwise, flow is subsonic:
        

      

           758
. 1

1 2 515
. 1

1 2 5 *

* 3430 * * 10 27
. 1 P P P P T A FR u (Eq. W
- 11 A )

Where:*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 33 of 151 FRa = Average flow rate in cubic f eet per hour, under

actual subsonic flow conditions. A = Cross sectional open area of the restriction

orifice (m2 ). P 1 = Upstream pressure (psia). T u = Upstream temperature (degrees Kelvin). P 2 = Downstream pressure (psia). 3430 = Constant with units of m2 /(sec 2 * K). 1.27*10 5 = Conversion from m 3 /second to ft 3 /hour.

u T A FR * 08
. 187 * * 10 27
. 1 5   (Eq. W
- 1 1B )
Where:
FRa = Average flow rate in cubic feet per hour, under

actual sonic flow conditions. A = Cross sectional open area of the restriction

orifice (m2 ). T u = Upstream temperature (degrees Kelvin). 187.08 = Constant with units of m2 /(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 P1 = Pressure upstream of the restriction orifice in

pounds per square inch absolute. P2 = Pressure downstream of the restriction orifice in

pounds per square inch absolute. (iii) For Equation W
- 10A, the ratio of backflow rate during well completions and workovers from hydraulic fracturing to 30
-*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 34 of 151 day production rate is calculated using Equation W
- 12 of this section.


##  

   W
p p W
p p PR FR FRM

1

1 (Eq. W
- 12)

Where:
FRMs = Ratio of flowback rate during well completions and

workovers from hydraulic fracturing to 30
- day production rate. FRs,p = Measured flowba ck rate from Calculation Methodology

1 described in paragraph (g)(1)(i) of this section or calculated flow rate from Calculation Methodology 2 described in paragraph (g)(1)(ii) of this section in standard cubic feet per hour for well(s) p for each sub
-basi n and well type (horizontal or vertical) combination. Measured and calculated FRa values shall be converted from actual conditions (FRa ) to standard conditions (FRs,p ) for each well p using Equation W
- 33 in paragraph (t) of this section. You may not use flow volume as used in Equation W
- 10B converted to a flow rate for this parameter. PRs,p = First 30
- day production rate 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, the ratio of backflow 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 35 of 151 gas producing sub
-basin and well type combination and to all horizontal and vertical well workovers, respectively, in the gas producing sub
-basin and well type combination for the total number of hours of backflow for each of these wells. (v) For Equation W
- 10A, new flow rates for horizontal and vertical gas well completions and horizontal and vertical gas well workovers in each sub
-basin category shall be calcu lated once every two years starting in the first calendar year of data collection. (2) The volume 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 us ing receipts of gas purchases that are used for the energized fracture job. (i) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section. (ii) [Reserved] (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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 36 of 151 (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 e stimate based on best available data. (ii) [Reserved] (iii) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section. (4) Both CH 4 and CO 2 volumetric and mass emissions shall be calculated from volumetric total emissions using calculations in paragraphs (u) and (v) of this section. (5) Calculate annual emissions from gas well venting during well completions and workovers from hydraulic fracturing to flares as follows: (i) Use the total gas well venting volume dur ing well completions and workovers as determined in paragraph (g) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine gas well venting during well completions and workovers using hydraulic fra cturing 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 37 of 151 (h) Gas well venting during completions and workovers without hydraulic fracturing . Calculate CH 4 , CO 2 and N 2 O emissions from each gas well venting during well completions and workovers not involving hydraulic fracturing using Equation W
- 13 of this section:

p f

p p wo wo n s 

### T

V EF N E *

* 1 , 

# 

 

###   (Eq. W
- 13)

Where:
E s,n = Annual natural gas emissions in standard cubic feet

from gas well venting during well completions and workovers without hydraulic fracturing. Nwo = 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. EFwo = Emission Factor for non
- hydraulic fracture well

workover venting in standard cubic feet per workover. EFwo = 3114 standard cubic feet natural gas per well workover 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. Vp = Average daily gas production rate in standard cubic

feet per hour for each well completion without hydraulic fracturing, p. This is the total annual gas production volume divided by total number of hours the wells produced to the flow
- line. For completed wells that have not established a production rate, you may use the average flow rate from the first 30 days of production. In the event that the well is completed less than 30 days from the end of the calendar year, the first 30 days of the production straddling the current and following calendar years shall be used.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 38 of 151 T p = Time each well completion without hydraulic

fracturing, p, was venting in hours during the year. (1) Volumetric emissions for both CH 4 and CO 2 shall be calculated from volumetric natural gas emissions using calculations in paragraph (u) of this section. Mass emissions for both CH 4 and CO 2 shall be calculated from volumetric natural gas emissions using calculations in paragraphs (v) of this section. (2) Calculate annual emissions from gas well venting during well completions and workovers not involving hydraulic fracturing to flares as follows: (i) Use the gas well venting vol ume during well completions and workovers as determined in paragraph (h) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine gas well venting during well completions and workovers emissions wi thout hydraulic fracturing from the flare. (i) Blowdown vent stacks . Calculate CO 2 and CH 4 blowdown vent stack emissions from depressurizing equipment(s) to reduce system pressure for planned or emergency shutdowns resulting from human intervention or to t ake equipment out of service for maintenance (excluding depressurizing to a flare, over
-pressure relief, operating pressure control venting and blowdown of non
-*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 39 of 151 GHG gases; desiccant dehydrator blowdown venting before reloading is covered in paragraph (e)(5) of this section) as follows: (1) Calculate the unique physical volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, discharge bottles, and vessels) between isolation valves determined by engineering estimates based on bes t 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, he aders, fractionators, and tanks). Unique physical volumes smaller than 50 cubic feet are exempt from reporting under paragraph (i) of this section. (3) Calculate the total annual venting emissions for unique volumes using either Equation W
- 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 *

, (Eq. W
- 14A)

Where:
E s,n = Annual natural gas venting emissions at standard

conditions from blowdowns in cubic feet. N = Number of occurrences of blowdowns for each unique

physical volume in calendar year.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 40 of 151 V = Unique ph ysical volume (including pipelines,

compressors and vessels) between isolation valves in cubic feet. C = Purge factor that is 1 if the unique physical

volume is not purged or zero if the unique physical volume is purged using non
- GHG gases. T s = Temperatur e 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).



##  

#     

## 

                     N
p s a p

e a p b a s n s P T P P T V E 1 , , , ,
, 67

. 459 67
. 459 (Eq. W
- 14B)

Where:
E s,n = Annual natural gas venting emissions at standard

conditions from blowdowns 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 = Total 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 actua l conditions in the unique

physical volume ( °F) for each blowdown “p”. P s = Absolute pressure at standard conditions (14.7

psia). P a,b,p = Absolute pressure at actual conditions in the

unique physical volume (psia) at the beginning of the blowdown “p”.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 41 of 151 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. (4) Calculate both CH 4 and CO 2 volumetric and mass emissions using calculations in paragr aph (u) and (v) of this section. (j) Onshore production storage tanks . Calculate CH 4 , CO 2 and N 2 O (when flared) emissions from atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore petroleum and natural gas produ ction facilities (including stationary liquid storage not owned or operated by the reporter), calculate annual CH 4 and CO 2 emissions using any of the calculation methodologies described in this paragraph (j). (1) Calculation Methodology 1 . For separators with annual average daily throughput of oil greater than or equal to 10 barrels per day. Calculate annual CH 4 and CO 2 emissions from onshore production storage tanks using operating conditions in the last wellhead gas
- liquid separator before liquid transfe r to storage tanks. Calculate flashing emissions with a software program, such as AspenTech HYSYS ® or API 4697 E&P Tank, that uses the Peng
- Robinson equation of state, models 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 following parameters determined for typical*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 42 of 151 operating conditions over the year by engineering estimate and process knowledge based on best available data must be used 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 available, determine these parameters by selecting one of the methods described under paragraph (j)(1) (vii) of this section. (A) If separator oil composition and Reid vapor pressure default data are provided with the software program, select the default values that most closely match your separator pressure first, and API gravity secondarily. (B) If separator oil composition and Reid vapor pressure data are available thr ough 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 an d Reid vapor*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 43 of 151 pressure using an appropriate standard method published by a
consensus -based standards organization. (2) Calculation Methodology 2 . Calculate annual CH 4 and CO 2
emissions from onshore production storage tanks for wellhead gas - liquid separators with annual average daily throughput of oil greater than or equal to 10 barrels per day by assuming that all of the CH 4 and CO 2 in solution at separator temperature and pressure is emitted from oil sent to storage tanks. You may use an appropriate standar d method published by a consensus
-based standards organization if such a method exists or you may use an industry standard practice as described in § 98.234(b) to sample and analyze separator oil composition at separator pressure and temperature. (3) Calcul ation 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, calculate annual CH 4 and CO 2 emissions by either of the methods in paragraph (j)(3) of this section: (i) If well production oil and gas compositions are available through your previous analysis, select the latest available analysis that is representative of produced oil and*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 44 of 151 gas from the sub
-basin cate gory and assume all of the CH 4 and CO 2 in both oil and gas are emitted from the tank. (ii) If well production oil and gas compositions are not available, use default oil and gas compositions in software programs, such as API 4697 E&P Tank, that most closel y 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 production 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 45 of 151 best available data. Assume all of the CH 4 and CO 2 in the oil phase i s emitted from the tank. (5) Calculation Methodology 5 . For well pad gas
- liquid separators and for wells flowing off a well pad without passing through a gas
- liquid separator with annual average daily throughput of oil less than 10 barrels per day use Equa tion W
- 15 of this section: 

### 1000 * *

, 

### Count EF E i i s 

###  (Eq. W
- 15)
Where:
E s,i = Annual total volumetric GHG emissions (either CO 2 or

CH 4 ) at standard conditions in cubic feet. EF i = Population emission factor for separators or 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) Determine if the storage tank receiving your separato r oil has a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (j)(1) through (j)(5) of this section downward by the magnitude of*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 46 of 151 emissions recovered using a vapor recovery system as determined by engineering estimate based on best ava ilable data. (ii) [Reserved] (7) 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 methodology of flare stacks in paragraph (n) of this section to determine your contribution to storage tank emissions from the flare. (8) Calculate emissions from occurrences of well pad gas
liquid separator liquid dump valves not closing during the calendar year by using Equation W
- 16 of this section. 

##   

    

       
 n n n n n i s 

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

, (Eq. W
- 16)

Where:
E s,i = Annual total volumetric GHG emissions at standard

conditions from each storage tank in cubic feet. E n = Storage tank emissions as determined in Calculation

Methodologies 1, 2, or 4 in pa ragraphs (j)(1), (j)(2) and (j)(4) of this section (with wellhead separators) in standard cubic feet per year. T n = Total time the dump valve is not closing properly

in the calendar year in hours. T n is estimated by maintenance or operations records (recor ds) such that when a record shows the valve to be open improperly, it is assumed the valve was open for the entire time period preceding the record*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 47 of 151 starting at either the beginning of the calendar year or the previous record showing it closed properly with in the 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 ye ar. CFn = Correction factor for tank emissions for time

period T n is 3.87 for crude oil production. Correction factor for tank emissions for time period T n is 5.37 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) Calculate both CH 4 and CO 2 mass emissions from volumetric natural gas emissions using calculations in paragraph (v) of this section. (k) Transmission storage tanks . For vent stacks connected to one or more transmission condensate storage tanks, either water or hydrocarbon, without vapor recovery, in onshore natural gas transmission compression, calculate CH 4 , CO 2 and N 2 O annual emissions from compressor scrubber dump valve leakage as follows: (1) Monitor the tank vapor vent stack annually for emissions using an optical gas imaging instrument according to methods set forth in § 98.234(a)(1) or by directly measuring the tank vent using a flow meter or high volume sampler according to methods in § 98.234(b) through (d) for a duration of 5 minutes,*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 48 of 151 or a calibrated bag according to methods in § 98.234(b). Or you may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak detection device according to methods set forth in § 98.234(a)(5). (2) If the tank vapors from the vent stack are continuous for 5 minutes, or the acoustic leak detection device detects a leak, then use one of the following two methods in paragraph (k)(2) of this se ction to quantify annual emissions: (i) Use a meter, such as a turbine meter, calibrated bag, or high flow 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) of this section to detect continuous leakage, this serves as the measurement. (ii ) Use an acoustic leak detection device on each scrubber dump valve connected to the tank according to the method set forth in § 98.234(a)(5). (iii) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section. (iv) Calculate GHG volumetric and mass emissions at standard conditions using calculations in paragraphs (t), (u),*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 49 of 151 and (v) of this section, as applicable to the monitoring equipment used. (3) If the leaking dump valve(s) is fixed following leak detection, the annual emissions shall be calculated from the beginning of the calendar year to the time the valve(s) is repaired. (4) Calculate annual emissions from storage tanks to flares as follows: (i) Use the storage tank emissions volume and gas composition as determined in paragraphs (k)(1 ) through (k)(3) of this section. (ii) Use the calculation methodology 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: (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 da ta, then you must measure quantities reported in this section*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 50 of 151 according to one of the two procedures in paragraph (l)(2) of this section to determine GOR: (i) You may use an appropriate standard method published by
a consensus -based standards organization if such a method exists. (ii) Or you may use an industry standard practice as described in § 98.234(b). (3) Estimate venting emissions using Equation W
- 17A or Equation W
- 17B of this section. 

### D FR GOR E n a 

### *

*

, 

###  (Eq. W
- 17 A )



### 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 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 year, the well(s) is

tested. (4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 51 of 151 (5) 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 sectio n. (6) Calculate emissions from well testing to flares as follows: (i) Use the well testing emissions volume and gas composition as determined in paragraphs (l)(1) through (3) of this section. (ii) Use the calculation methodology 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 , CO 2 and N 2 O (when flared) 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: (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, the GOR from a cluster of well s in the same sub
-basin category shall be used. (2) If GOR cannot be determined from your available data, then use one of the two procedures in paragraph (m)(2) of this section to determine GOR:*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 52 of 151 (i) You may use an appropriate standard method published by
a consensus -based standards organization if such a method exists. (ii) Or you 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 , , , (Eq. W
- 18)

Where:
E a,n = Annual volumetric natural gas emissions, at the

facility level, from associated gas venting under actual conditions, in cubic feet. GORp,q = Gas to oil ratio, for well p in sub
-basin q, in

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

in barrels in the calendar year during which associated gas was vented or flared.
x = Total number of wells in sub
-basin that vent or

flare associa ted 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 53 of 151 (5) 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) Calculate emissions from associated natural gas to flares as follows: (i) Use the associated natural gas volume and gas composition as determined in paragraph (m)(1) through (4) of this section. (ii) Use the calculation methodology 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: (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 devi ce on the flare or use engineering calculations based on process knowledge, company records, and best available data.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 54 of 151 (2) If you have a continuous gas composition analyzer on gas to the flare, you must use these compositions in calculating emissions. If you do not have a continuous gas composition analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare as follows: (i) For onshore natural gas production, determine natural gas composition using (u)(2)(i) of this section. (ii) For onshore natural gas processing, when the stream going to flare is natural gas, use the GHG mole percent in feed natural gas for all streams upstream of the de
-methanizer or dew point control, and GHG mole percent i n 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 gas processing plants that solely fr actionate a liquid stream, use the GHG mole percent in feed natural gas liquid for all streams. (iii) For any applicable industry segment, when the stream going to the flare is a hydrocarbon product stream, such as methane, ethane, propane, butane, pentane
-plus and mixed light hydrocarbons, then you may use a representative composition from*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 55 of 151 the source for the stream determined by engineering calculation based on process knowledge and best available data. (3) Determine flare combustion efficiency from manufa cturer. If not available, assume that flare combustion efficiency is 98 percent. (4) Calculate GHG volumetric emissions at actual conditions using Equations W
- 19, W
- 20, and W
- 21 of this section.



###   4 4 , * ) 1 ( * CH a CH a X V combusted un E     (Eq. W
- 19) 

##   2 2 , * CO a CO a X

V combusted un E 

 (Eq. W
- 20) 

##   

##  



  5
1 2 , * * * J j

j a CO a R Y V combusted E  (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 emission s from flare stack in cubic feet, under actual conditions. E a, CO2 (combusted) = Contribution of annual combusted CO 2 emissions from flare stack in cub ic feet, under actual conditions. Va = Volume of gas sent to flare in cubic feet, during

the year. η = Fraction of gas combusted by a burning flare

(default is 0.98). For gas sent to an unlit flare, η is zero. XCH4 = Mole fraction of CH 4 in gas to the flare. XCO2 = Mole fraction of CO 2 in gas to the flare.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 56 of 151 Y j = Mole fraction of gas hydrocarbon constituents j

(such as methane, ethane, propane, butane, and pentanes -plus). Rj = 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). (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) If you operate and maintain a CEMS that has both a CO 2 concentration monitor and volumetric flow rate monitor, you must calculate only CO 2 emissions for the flare. You must follow the Tier 4 Calculation Methodology and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). If a CEMS is used to calculate flare stack emiss ions, the requirements specified 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 57 of 151 flow rate monito r that comply with all of the requirements specified for the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion). (10) The flare emissions determined under 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, Va , in these equations. (o) Centrifugal compressor venting . Calculate CH 4 , CO 2 and N 2 O (when flared) emissions from both wet seal and dry seal centrifugal compressor vents as follows: (1) For each centrifugal compressor covered by § 98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) you must conduct an annual measurement in the operating mode in which it is found. Measure emissions from all vents (including emissions manifolded to common vents) including wet seal oil degassing vents, unit iso lation valve vents, and blowdown valve vents. Record emissions from the following vent types in the specified compressor modes during the annual measurement. (i) Operating mode, blowdown valve leakage through the blowdown vent, wet seal and dry seal compre ssors.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 58 of 151 (ii) Operating mode, wet seal oil degassing 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 stan dby 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. (2) For wet seal oil degassing vents, determine vapor volumes sent to an atmospheric vent or flar e, using a temporary meter such as a vane anemometer or permanent flow meter according to 98.234(b) of this section. If you do not have a permanent flow meter, you may install a permanent flow meter on the wet seal oil degassing tank vent. (3) For blowdown valve leakage and unit isolation valve leakage to open ended vents, you can use one of the following methods: Calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. For through valve leakage, s uch as isolation valves, you may use*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 59 of 151 an acoustic leak detection device according to methods set forth in § 98.234(a). If you do not have a flow meter, you may install a port for insertion of a temporary meter, or a permanent flow meter, on the vents. (4) Es timate annual emissions using the flow measurement and Equation W
- 22 of this section. 

### ) 1 ( * * *

, , , m m i m m m i s 

### B

M T MT E

  (Eq. W
- 22)
Where:
E s,i,m = Annual GHG i (either CH 4 or CO 2 ) volumetric

emissions at standard conditions, in cubic feet. MTm = Measured gas emissions in standard cubic feet per

hour. Tm = Total time the compressor is in the mode for which

E s,i is being calculated, in the calendar year in hours. Mi,m = Mole fraction of GHG i in the vent gas; use the

appropriate gas compositions in paragraph (u)( 2) of this section. Bm = Fraction of operating time that the vent gas is

sent to vapor recovery or fuel gas as determined by keeping logs of the number of operating hours for the vapor recovery system and the time that vent gas is directed to the fuel gas system or sales. (5) Calculate annual emissions from each centrifugal compressor using Equation W
- 23 of this section.



##   m i

m m i s GHG

T EF E *

*

, (Eq. W
- 23)

Where:*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 60 of 151 E s,i,m = Annual total volumetric GHG emissions at standard

conditions from each centrifugal comp ressor for mode
- source combination m, in cubic feet. EFm = Reporter emission factor for each mode m, in cubic

feet per hour, from Equation W
- 24 of this section as calculated in paragraph 6. Tm = Total time in hours per year the compressor was in

each mode, as listed in paragraph (o)(1)(i) through (o)(1)(iii). GHG i = For onshore natural gas processing facilities,

concentration of GHG i , CH 4 or CO 2 , in produced natural gas or feed natural gas; for other facilities listed in § 98.230(a)(4) through (a)(8),GHG i equals 1. (6) You shall use the flow measurements of operating mode wet seal oil degassing vent, operating mode blowdown valve vent and not operating depressurized mode isolation valve 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 mode as listed in paragraph (o)(1)(i) through (o)(1)(iii). 

#   m

m m Count MT EF (Eq. W
- 24)

Where:
EFm = Reporter emission factors for compre ssor in the

three modes m (as listed in paragraph (o)(1)(i) through (o)(1)(iii)) in cubic feet per hour. MTm,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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 61 of 151 Countm = Total number of compressors measured.
m = Compressor mode
- source combination as listed in

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

i i s 

### EF Count E *

, 

###  (Eq. W
- 25)
Where:
E s,i = Annual total volumetric GHG emissions at standard

conditions from centrifugal compressor wet seals in cubic feet. Count = Total number of centrifugal compressors for the

reporter. EF i = Emission factor for GHG i . Use 1.2 × 10 7 standard

cubic feet per year per compressor for CH 4 and 5.30 × 10 5 standard cubic feet per year per compressor for CO 2 at 60 °F and 14.7 psia. (8) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 62 of 151 (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 i n paragraphs (o)(5) of this section. (ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine degassing vent vapor emissions from the flare. (p) Reciprocating compressor venting . Calculate CH 4 and CO 2
emissions fr om all reciprocating compressor vents as follows. For each reciprocating compressor covered in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must conduct an annual measurement for each compressor in the mode in which it is 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 blowdown valve vents. Record emissions from the fo llowing vent types in the specified compressor modes during the annual measurement as follows: (1) Operating or standby pressurized mode, blowdown vent leakage through the blowdown vent stack. (2) Operating mode, reciprocating rod packing emissions. (3) No t operating, depressurized mode, unit isolation valve leakage through the blowdown vent stack, without blind flanges.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 63 of 151 (i) For the not operating, depressurized mode, each compressor must be measured at least once 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 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. (ii) [Reserved] (4) If reciprocating rod packing and blowdown vent are connected to an open
- ended vent line use one of the following two meth ods 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 or high volume sampler according to methods s et 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 manifolded to a common vent) including rod pack ing vents and unit isolation valve leakage through blowdown vents according to methods set forth in*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 64 of 151 § 98.234(b). If you do not have a permanent flow meter, you may install a port for insertion of a temporary meter or a permanent 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 according to methods set forth in § 98.234(a). (5) If reciprocating rod packing is not equipped with a vent line use the following method to calculate emissions: (i) You must use the methods described in § 98.234(a) to conduct annual leak detection of equipment leaks from the packing case into an open dist ance piece, or from the compressor crank case breather cap or other vent with a closed distance piece. (ii) Measure emissions found in paragraph (p)(5)(i) of this section using an appropriate meter, or calibrated bag, or high volume sampler according to me thods set forth in § 98.234(b), (c), and (d), respectively. (6) Estimate annual emissions using the flow measurement and Equation W
- 26 of this section.

m i m m m i s 

### M

T MT E

, , , 

### * *  (Eq. W
- 26)
Where:*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 65 of 151 E s,i,m = Annual GHG i (either CH 4 or CO 2 ) volumetric

emissions at standard conditions, in cubic feet. MTm = Measured gas emissions in standard cubic feet per

hour. Tm = Total time the compressor is in the mode for which

E s,i,m is being calculated, in the calendar year in hours. Mi,m = Mole fraction of GHG i in gas; u se the appropriate

gas compositions in paragraph (u)(2) of this section. (7) Calculate annual emissions from each reciprocating compressor using Equation W
- 27 of this section.



##   m i

m 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. EFm = Reporter emission factor for each mode, m, in cubic

feet per hour, from Equation W
- 28 of this section as calculated in paragraph (p)(7)( i) of this section. Tm = Total time in hours per year the compressor was in

each mode, m, as listed in paragraph (p)(1) through (p)(3). GHG i = For onshore natural gas processing facilities,

concentration of GHG i, CH 4 or CO 2 , in produced natural gas or fee d natural gas; for other facilities listed in § 98.230(a)(4) through (a)(8), GHG i equals 1.
m = Compressor mode as listed in paragraph (p)(1)

through (p)(3). (i) You shall use the flow meter readings from measurements of operating and standby pressurized bl owdown vent, operating*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 66 of 151 mode vents, not operating depressurized isolation valve vent for all the reporter's compressor modes not measured in the calendar year to develop the following emission factors using Equation W
28 of this section for each mode as lis ted in paragraph (p)(1) through (p)(3). 

#   m

m m Count MT EF (Eq. W
- 28)

Where:
EFm = Reporter emission factors for compressor in the

three modes, m, in cubic feet per hour. MTm,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. Countm = Total number of compressors measured in each mode,

m. m = Compressor mode
- source combination as listed in

(p)(1) through (p)(3). (A) You must combine emissions for blowndown vents, measured in the operating and standby pressurized modes. (B) The emission factors must be calculated annually. You must use all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar years of measurements. (ii) [Reserved]*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 67 of 151 (8) Determine if the reciprocating compressor vent vapors are sent to a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (p)(7) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data. (ii) [Reserved] (9) Onshore petroleum and natural gas production shall calculate emissions from reciprocating compressors as follows:

i i s 

### EF Count E *

, 

###  (Eq. W
- 29)
Where:
E s,i = Annual total volumetric GHG emissions at standard

conditions from reciprocating compressors in cubic feet. Count = Total number of reciprocating compressors for the

reporter. EF i = Emission factor for GHG i . Use 9.48 × 10 3 standard

cubic feet per year per compressor for CH 4 and 5.27 × 10 2 standard cubic feet per year per compressor for CO 2 at 60 °F and 14.7 psia. (10) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in paragraphs (u) and (v) of this section. (q) Leak detection and leaker emission factors . You must use the methods described in § 98.234(a) to conduct leak detection(s) of equipment leaks from all component types listed*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 68 of 151 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 10 percent CH 4 plus CO 2 by weight 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 equipment leaks are detected for sources listed in this paragraph (q), calculate equipment leak emissions per component type per reporting facility using Equations W
- 30A or W- 30B of this section for each component type. Use Equation W
30A for industry segments listed in 98.230(a)(3)
- (a)(7). Use Equation W
- 30B for industry segments list ed in 98.230(a)(8). 

#   

  x

p p i i s T

EF GHG E 1 , *

* (Eq. W
- 30A) 

#    

    t

n

t q x
p q

p i i s T

EF GHG E 1 1 , , *

* (Eq. W
- 30B)

Where:
E s,i = Annual total volumetric GHG emissions at standard

conditions from each component type in cubic feet, as specified in (q)(1) through (q)(8) of this sec tion.
x = Total number of each component type. EF = Leaker emission factor for specific component types

listed in Table W
- 2 through Table W
- 7 of this subpart.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 69 of 151 GHG i = For onshore natural gas processing facilities,

concentration of GHG i , CH 4 or CO 2 , in the t otal 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 = The total time the component, p, was found leaking

and operational, in hours. If one leak detection survey is conducted, assume the component was leaking for the entire calendar year. If multiple leak detection surveys are conducted, assume that the component found to be leaking has been leaking since the previous survey (if not found leaking in the previous survey) or the beginning of the calendar year (if it was found leaking in the previous survey). For the last leak detection survey in the calendar year, assume that all leaking components continue to leak until the end of the calendar year. t = Calendar year of reporting.
n = The number of years over which one c omplete 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 is availabl e. 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 conducted, 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 70 of 151 (1) You must select to conduct either one leak detection survey in a calendar year or multiple complete leak detection surveys in a calendar year. The number of leak detection surveys selected must be conducted during the calendar year. (2) Calculate GHG mass emissions in carbon dioxide equivalent at standard conditions using calculations in paragraph (v) of this section. (3) Onshore natural gas processing facilities shall use the appropriate default leaker emission factors listed in Table W
- 2 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters. (4) Onshore natural gas transmission compre ssion facilities shall use the appropriate default leaker emission factors 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 f acilities for storage stations shall use the appropriate default leaker emission factors listed in Table W
- 4 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 71 of 151 (6) LNG storage facilit ies shall use the appropriate default leaker emission factors listed in Table W
- 5 of this subpart for equipment leaks detected from valves, pump seals, connectors, and other. (7) LNG import and export facilities shall use the appropriate default leaker emi ssion factors listed in Table W
- 6 of this subpart for equipment leaks detected from valves, pump seals, connectors, and other. (8) Natural gas distribution facilities for above grade transmission
- distribution transfer stations, shall use the appropriate de fault leaker emission factors 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 gas distributi on facilities is only required at above grade stations that qualify as transmission
- distribution transfer stations. Below grade transmission
- distribution transfer stations and all metering
- regulating stations that do meet the definition of transmission
- dis tribution transfer stations are not required to perform component leak detection under this section. (i) Natural gas distribution facilities may choose to conduct leak detection at the T
- D transfer stations over*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 72 of 151 multiple years, not exceeding a five year pe riod to cover all T
D transfer stations. If the facility chooses to use the multiple year option then the number of T
- D 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] (r) Population count and emission factors . This paragraph applies to emissions sources listed in § 98.232 (c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on streams with gas content greater than 10 percent CH 4 plus CO 2 by weight. Emissions sources in streams with gas content less than 10 percent CH 4 plus CO 2 by weight do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt f rom the requirements of paragraph (r) of this section and do not need to be reported. Calculate emissions from all sources listed in this paragraph using Equation W
- 31 of this section.

s i s s i s 

### T

GHG EF Count E *

* *

, 

###  (Eq. W
- 31)
Where:
E s,i = Annual volumetric GHG emissions at standard

conditions from each component type in cubic feet. Count s = Total number of this type of emission source at the

facility. For onshore petroleum and natural gas*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 73 of 151 production, average component counts are provided by major equipment piece in Tables W
- 1B and Table W- 1C of this subpart. Use average component counts as appropriate for operations in Eastern and Western U.S., according to Table W
- 1D of this subpart. Underground natural gas storage shall count the components listed for populatio n emission factors in Table W
- 4. LNG Storage shall count the number of vapor recovery compressors. LNG import and export shall count the number of vapor recovery compressors. Natural gas distribution shall count the meter/regulator runs as described in par agraph (r)(6) of this section. EF = Population emission factor for the specific

component type, as listed in Table W
- 1A and Tables W- 3 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
- 32 of this section. 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 exp ort 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 s = Average estimated time that each component type

associated with the equipment leak emission was operational in the calendar year, in hours, 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 74 of 151 (2) Onshore petroleum and natural gas production faciliti es shall use the appropriate default population emission factors listed in Table W
- 1A of this subpart for equipment leaks from valves, connectors, open ended lines, pressure relief valves, pump, flanges, and other. Major equipment and components associated with gas wells are considered gas service components in reference to Table W
- 1A of this subpart and major natural gas equipment in reference to Table W
- 1B of this subpart. Major equipment and components associated with crude oil wells are considered crude service components in reference to Table W
- 1A of this subpart and major crude oil equipment in reference to Table W
- 1C of this subpart. Where facilities conduct EOR operations the emissions factor listed in Table W
- 1A of this subpart shall be used to estimate all streams of gases, including recycle CO 2 stream. The component count can be determined using either of the methodologies described in this paragraph (r)(2). The same methodology must be used for the entire calendar year. (i) Component Count Methodo logy 1 . For all onshore petroleum and natural gas production operations in the facility perform the following activities:*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 75 of 151 (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

-p ad. (B) Multiply major equipment counts by the average component counts listed in Table W
- 1B and W
- 1C of this subpart for onshore natural gas production and onshore oil production, respectively. Use the appropriate factor in Table W
- 1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W
- 1D of this subpart. (ii) Component Count Methodology 2 . Count each component individually for the facility. Use the appropriate factor in Table W
- 1A of this subpart for operations i n 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 use the appropriate default population emission factors 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 use the appropriate default population emission factors listed in Table W
- 5 of this subpart for equipment leak from vapor recovery compress ors. (5) LNG import and export facilities shall use the appropriate default population emission factor listed in Table*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 76 of 151 W- 6 of this subpart for equipment leak from vapor recovery compressors. (6) Natural gas distribution facilities shall use the appropriate emission factors as described in paragraph (r)(6) of this section. (i) Below grade metering
- regulating stations; distribution mains; and distribution services, shall use the appropriate default population emission factors listed in Table W
- 7 of this subpa rt. Below grade T
- D transfer stations shall use the emission factor for below grade metering
- regulating stations. (ii) 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 emission factor in Equation W
- 32 will be cal culated 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 located at above grade transmission
- distributio n transfer stations that were monitored over the years that constitute one complete cycle as per paragraph (q)(8)(i) of this section. A*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 77 of 151 meter on a regulator run is considered one meter/regulator run. Reporters that do not have above grade T
- D transfer stat ions 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 transfer stations, from Equation W
30B. Count = Tot al 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 fa cilities . 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 and 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 78 of 151 calculated and reported by BOEMRE in data collection and emissions estimation study published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). (i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication year, report the most recent BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). Adjust emissions based on the operating time for the facility relative to the operating time in the most recent BOEMRE published study. (ii) [Reserved] (2) Offshore production facilities that are not under BOEMRE jurisdiction s hall use monitoring methods and calculation methodologies published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS). (i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication, report the most recent reported emissions data with emissions adjusted based on the operating time for the facility relative to operating time in the previous reporting period. (ii) [Reserved] (3) If BOEMRE discontinues or delays their data coll ection effort by more than 4 years, then offshore reporters shall once in every 4 years use the most recent BOEMRE data collection and*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 79 of 151 emissions estimation methods to report emission from the facility sources. (4) For either first or subsequent year report ing, offshore facilities either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle shall use the most recent BOEMRE data collection and emissions estimation methods published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS) to report emissions. (t) Volumetric emissions . If equation parameters in § 98.233 are already at standard conditions, which results in volumetric emissions at standard conditions, then thi s paragraph does not apply. Calculate volumetric emissions at standard conditions as specified in paragraphs (t)(1) or (2) of this section, with actual pressure and temperature determined by engineering estimates based on best available data unless otherwi se specified. (1) Calculate natural gas volumetric emissions at standard conditions using actual natural gas emission temperature and pressure, and Equation W
- 33 of this section for conversions of E a,n or conversions of FRa (whether sub
- sonic or sonic). 

##     s

a a s n a n s P

T P T E E *

67
. 459 * 67
. 459 *

,
,    (Eq. W
- 33)*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 80 of 151 Where:
E s,n = Natural gas volumetric emissions at standard

temperature and pressure (STP) conditions in cubic feet, except E s,n equals FRs,p for each well p when calculating either subsonic or sonic flowrates under 98.233(g ). E a,n = Natural gas volumetric emissions at actual

conditions in cubic feet, except E a,n equals FRa,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 a t actual emission conditions (°F). P s = Absolute pressure at standard conditions (14.7

psia). P a = Absolute pressure at actual conditions (psia). (2) Calculate GHG volumetric emissions at standard conditions using actual GHG emissions temperature and press ure, and Equation W
- 34 of this section.

(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).     s a a s i a i s P

T P T E E *

67
. 459 * 67
. 459 *

,
,   *****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 81 of 151 (3) Reporters using 68 °F for standard temperature may use the ratio 519 .67/527.67 to convert volumetric emissions from 68 °F to 60 °F. (u) GHG volumetric emissions . 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 ) volumetri c emissions at

standard conditions in cubic feet. E s,n = Natural gas volumetric emissions at standard

conditions in cubic feet. Mi = Mole fraction of GHG i in the natural gas. (2) For Equation W
- 35 of this section, the mole fraction, Mi , shall be the annua l 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
co ntinuous gas composition analyzer for produced natural gas, i n s i s M E E *

, , *****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 82 of 151 you must use an annual average of these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then you must use an annual average gas composition base d 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 GHG mole fract ion 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 gas processing plants that sole ly 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 co ntinuous gas composition analyzer, then annual samples must be taken according to methods set forth in § 98.234(b). (iii) GHG mole fraction in transmission pipeline natural gas that passes through the facility for the onshore natural gas transmission compression industry segment. You may use a default*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 83 of 151 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (iv) GHG mole fraction in natural gas stored in the underground natural gas storage industry segment. You may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (v) GHG mole fraction in natural gas stored in the LNG storage industry segment. You may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (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 a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities. You may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas. (v) GHG mass emissions . Calculate GHG mass emissions in carbon dioxide equivalent by converting the GHG volumetric*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 84 of 151 emissions at standard conditions into mass emissions using Equation W
- 36 of this section.

3

, 10

* * *   GWP E Mass i

i s i  (Eq. W
- 36) Where:
Mass i = GHG i (either CH 4 , CO 2, or N 2 O ) mass emission s 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. Pi = 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 as follows: (1) Calculate the total volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves. (2) Retain logs of the number of blowdowns per calendar year. (3) Calculate the total annual venting emissions 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 emissions in

metric tons from blowdowns. N = Number of blowdowns for the equipment in the

calendar year.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 85 of 151 Vv = Total volume in cubic feet of blowdown equipment

chambers (including pipelines, manifolds and vessels) between isolation valves. Rc = Density of critical phase EOR in jection gas in

kg/ft 3 . You may use an appropriate standard method published by a consensus
-based standards organization if such a method exists or you may use an industry standard practice to determine density of super critical EOR injection gas. GHGCO2 = Mass fraction of CO 2 in critical phase injection

gas. 1 × 10 −3 = Conversion factor from kilograms to metric tons. (x) EOR hydrocarbon liquids dissolved CO 2 . Calculate 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 must be taken according to methods set forth in § 98.234(b) to determine retention of CO 2 in hydrocarbon liquids immediately downstream o f the storage tank. Use the annual analysis for the calendar year. (2) Estimate emissions using Equation W
- 38 of this section.

Mass CO2 = S hl * Vhl (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 in

metric tons per barrel, under standard conditions.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 86 of 151 Vhl = Total volume of hydrocarbon liquids produced at the

EOR operations in barrels in the calendar yea r. (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 (z)(1)(i ). 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 methodology described in (z)(1)(i) and you may use the emission factor provided for

n atural 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 (z)(2). If the fuel is field gas, process vent gas, or a blen d containing field gas or process vent gas, calculate emissions according to (z)(2). (i) For fuels listed in Table C
- 1 or a blend containing one or more fuels listed in Table C
- 1, calculate CO 2 , CH 4 , and N 2 O*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 87 of 151 emissions according to any Tier listed in subpar t 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 according to the requirements specified in 98. 236(c)(19) and not according to the reporting requirements specified in subpart C of this part. (2) For fuel combustion units that combust 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, calculate combustion emissions as follows: (i) You may use company records to determine the volume of fuel combusted in the unit during the reporting year. (ii) If you have a continuous gas composition analyzer on fuel to the combustion unit, you must use these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to the unit. If you do not have a continuous gas*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 88 of 151 composition analyze r on gas to the combustion unit, you must use the appropriate gas compositions for each stream of hydrocarbons going to the combustion unit as specified in the applicable paragraph in (u)(2) of this section. (iii) Calculate GHG volumetric emissions at actu al conditions using Equations W
- 39A and W
- 39B of this section: 

## 

   5
1

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



##   4 4 , *

1 * CH a CH a Y V E 

  (Eq. W
- 39B)
Where:
E a,CO2 = Contribution of annual CO 2 emissions from portable

or stationary fuel combustion sources in cubic feet, under actual conditions. Va = Volume of gas sent to combustion unit in cubic

feet, during the year. Y CO2 = Concentration of CO 2 constituent in gas sent to

combustion unit. E a,CH4 = Contribution of annual CH 4 emissions from portable

or stationary fuel combustion sources in cubic feet, under actual conditions. η = Fraction of gas combusted for portable and

stationary equipment determined using engineering estimation. For internal combustion devices, a default of 0.995 can be used. Y j = Concentration of gas hydrocarbon constituents j

(such as methane, ethane, propane, butane, and pentanes plus) in gas sent to combustion unit. Rj = 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 89 of 151 Y CH4 = Concentration of methane constituent in gas sent to

combustion unit. (iv) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (v) Calculate both combustion
- related CH 4 and CO 2 mass emissions from volumetric CH 4 and CO 2 emissions using calculation in paragraph (v) of this section. (vi) Calculate N 2 O mass emissions using Equation W- 40 of this section. 

#   GWP 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 or volume of the fuel combusted (mass or

volume per year, choose appropriately to be consistent with the units of HHV). HHV = For the higher heating value for field gas or

process vent gas, use 1.235 × 10 −3 mmBtu/scf for HHV. EF = Use 1.0 × 10 −4 kg N 2 O /mmBtu. 1 × 10 −3 = Conversion factor from kilograms to metric tons. GWP = Global warming potential, as listed in Table A
- 1 of

subpart A of this part. (3) External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissions or include these emissions for threshold*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 90 of 151 determination in § 98.231(a). You must report the type and number of each external fuel combustion unit. (4) Internal fuel combustion sources, not compressor
drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr (or the equivalent of 130 horsepower ), do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the type and number of each internal fuel combustion unit. § 98.234 Monitoring and QA/QC requirements . The GHG emissions data for petroleum and 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 p rovided in paragraph (a)(4) of this section. (1) Optical gas imaging instrument . Use an optical gas imaging instrument for equipment leak detection in accordance with 40 CFR part 60, subpart A, § 60.18 of the Alternative work practice for monitoring equipme nt leaks, § 60.18(i)(1)(i);*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 91 of 151 § 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: Detection Sensitivity Levels; § 60.18(i)(2)(ii) and (i ii) except the gas chosen shall be methane, and § 60.18(i)(2)(iv) and (v); § 60.18(i)(3); § 60.18(i)(4)(i) and (v); including the requirements for daily instrument checks and distances, and excluding requirements for video records. Any emissions detected by the optical gas imaging instrument is a leak unless screened with Method 21 (40 CFR part 60, appendix A
- 7) monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, you must operate the optical gas imaging instrument to image the source types required by this subpart in accordance with the instrument manufacturer's operating 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 instrumen t 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 92 of 151 Owners or operators must use alternative leak detection devices as described in paragraph (a )(1) or (a)(2) of this section to monitor inaccessible equipment leaks or vented emissions. (3) Infrared laser beam illuminated instrument . Use an infrared laser beam illuminated instrument for equipment leak detection. Any emissions detected by the infrar ed 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 illuminated instrument to detect the source types requ ired by this subpart in accordance with the instrument manufacturer's operating parameters. (4) [Reserved] (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. Acoustic*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 93 of 151 stethoscope type devices designed to detect thr ough valve leakage when put in contact with the valve body and that provide an audible leak signal but do not calculate a leak rate can be used to identify non
- leakers with subsequent measurement required to calculate the rate if through
- valve leakage is i dentified. Leaks are reported if a leak rate of 3.1 scf per hour or greater is measured. (b) You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure quantities reported in § 98.233 according to the procedure s in § 98.3(i) and the procedures in paragraph (b) of this section. You may use an appropriate standard method published by a
consensus -based standards organization if such a method exists or you may use an industry standard practice. Consensus
-based standa rds 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 Mechanical Engineers (ASME), the American Petroleum Institut e (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 temperature specified by the vent bag manufacturer*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 94 of 151 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 enclosing the emissions source to capture the entire emis sions and record the time required for completely filling the bag. If the bag inflates in less than one second, assume one second inflation time. (2) Perform three measurements of the time required to fill the bag, report the emissions as the average of the three readings. (3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t). (4) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in § 98.233(u) and (v). (d) Use a high volume sampler to measure emissions within the capacity of the instrument. (1) A technician following manufacturer instructions shall conduct measurements, including equipment manufacturer operating procedures and measurement methodolog ies relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creating backpressure on the source.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 95 of 151 (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 instrument manufacturer's manual. (3) Estimate natural gas volumetr ic emissions at standard conditions using calculations in § 98.233(t). Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in § 98.233(u) and (v). (4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH 4 by using calibrated gas samples and by following manufacturer's instructions for calibration. (e) Peng Robinson Equation of State means the equation of state defined by Equation W
- 41 of this section:

2 2 2 b bV V a b V RT p
m

m m 

 

   (Eq. W
- 41) Where:
p = Absolute pressure. R = Universal gas constant. T = Absolute temperature. Vm = Molar volume.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 96 of 151

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   (Eq. W
- 4 2 )

Where:

ω = Acentric factor of the species. T c = Critical temperature. P c = Critical pressure. (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 Emissi ons 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 deadl ine, 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 method requests submitted after the deadlines specified in th is section, and will consider requests which*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 97 of 151 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 al l 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 methods specified in paragraph (f)(1) of this section: (i) Mo nitoring 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 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) Well testing venting and flaring as specified in § 98.233(l).*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 98 of 151 (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), 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 that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this part. These sources include: (i) Recip rocating compressor rod packing venting in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 99 of 151 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). (iii) Acid gas removal vent 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, conne ctors, 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 natur al gas processing, onshore natural gas transmission compression, underground 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 transmission compression as specified in § 98.232(e)(3).*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 100 of 151 (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 speci fied in paragraph (f)(4) of this section. (iv) No request or approval 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 liste d in paragraph (f)(2), (f)(3), and (f)(4) of this section. (6) [Reserved] (7) [Reserved]*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 1 01 of 151 (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 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 mon itoring methods must be submitted 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 the 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 p rior 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 102 of 151 operators that submit both a timely notice of intent and extension request consistent with 98.234(f)(8)(ii) can automatically use BAMM 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 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 2 012. For 2012, when an owner or operator has submitted a notice of intent and a subsequent best available monitoring method extension request, use of best available monitoring methods will be valid, upon approval by the Administrator, until the date indica ted 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 September 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:*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 103 of 151 (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 infeasibil ity, 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 . 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 include, by way of example and not in limitation, clearly demonstrated data collection methods that do not meet safety regulations, technical infeasibili ty, or counter to other local, State, or Federal regulations, along with the reasons the owner or operator cannot*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 104 of 151 otherwise address the unique or unusual circumstances as required to be demonstrated in this paragraph. (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 satisfy the requirements for the 2011
- 2012 da ta collection cycle. (h) [Reserved] § 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 an error occurs during annual emissions estimation or measurements, 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 until after December 31 of the year in which data are collected, until valid data for reporting is obtained. Data developed and/or collecte d in a subsequent calendar year to substitute for missing data cannot be used for that subsequent year's emissions estimation. Where missing data procedures are used for the previous year, at least 30 days must separate emissions estimation or measurements for the previous year and*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 105 of 151 emissions estimation or measurements for the current year of data collection. For missing data which are continuously monitored or measured, (for example flow meters), or for missing temperature or pressure data that are required under § 98.236, the reporter may use best available data for use in emissions determinations. The reporter must record and report the basis for the best available data in these cases. § 98.236 Data reporting requirements . In addition to the information requ ired by § 98.3(c), each annual report must contain reported emissions and related information as specified in this section. (a) Report annual emissions in metric tons of CO 2 e for each GHG separately for each of the industry segments listed in paragraphs (a) (1) through (8) of this section. (1) Onshore petroleum and natural gas production. (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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 106 of 151 (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) i ndividually 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 in dustry segment, each piece of equipment should be reported under the unit's respective majority use segment. When a source type listed under this paragraph routes gas to flare, separately report the emissions that were vented directly to the atmosphere without flaring, and the emissions that resulted from flaring the gas. Both the vented and flared emissions will be reported under the respective source type and not under the flare source type. (1) For natural gas pneumatic devices (refer to Equation W
1 of § 98.233), report the following: (i) Actual count and estimated count separately of natural gas pneumatic high bleed devices as applicable. (ii) Actual count and estimated count separately of natural gas pneumatic low bleed devices as applicable. (iii) Actu al count and estimated count separately of natural gas pneumatic intermittent bleed devices as applicable.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 107 of 151 (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; low bleed pneumatic devices. (2) For natural gas driven pneumatic pumps (refer to Equation W
- 2 of § 98.233), report the following, (i) Count of natural gas driven pneumatic pumps. (ii ) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons CO 2 e for each gas, for all natural gas driven pneumatic pumps combined. (3) For each acid gas removal unit (refer to Equation W
- 3 and Equation W
- 4 of § 98.233), report the following: (i) Total throughput off the acid gas removal unit using a meter or engineering estimate based on process knowledge or best available data in million cubic feet per year. (ii) For Calculation Methodology 1 and Calculation Methodology 2 of § 98.2 33(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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 108 of 151 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 throughput greater than or equal to 0.4 MMscfd (refer to § 98.233(e)(1)), report the following: (A) Glycol dehydrator feed natural gas flow rate in MMscfd, determined by engineering estimate based on best available data. (B) Glycol dehydrator absorbent circulation pump type. (C) Whether stripper gas is used in glycol dehydrator. (D) Whether a flash tank separator is used in glycol dehydrator. (E) Type of absorbent.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 109 of 151 (F) Total time the glycol dehydrator is operating in hours. (G) Temperature, in degrees Fahrenheit 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 § 98.2 33(e)(3) and (e)(4)). (J) For each glycol dehydrator, report annual CO 2 and CH 4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 e for each gas. (K) For each glycol dehydrator, report annual CO 2 , CH 4 , and N 2 O emissions that resulted from flaring process gas from the dehydrator, expressed in metric tons CO 2 e for each gas. (L) For the onshore natural gas processing industry segment only, report a unique name or ID number for glycol dehydrator. (ii) For all glyco l dehydrators with a throughput less than 0.4 MMscfd (refer to § 98.233, Equation W
- 5 of § 98.233), report the following: (A) Count of glycol dehydrators. (B) Which vent gas controls are used (refer to § 98.233(e)(3) and (e)(4)). (C) Report annual CO 2 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 110 of 151 glycol dehydrators with annual average daily throughput of less than 0.4 MMscfd. (D) Report annual CO 2 , CH 4 , and N 2 O emissions at the facility level that resulted from the flaring of process gas, expressed in metric tons CO 2 e for each gas, combined for all glycol dehydrators with annual average daily throughput of less than 0.4 MMscfd. (iii) For absorbent desiccant dehydrators (refer to Equation W
- 6 of § 98.233), report the following: (A) Count of desiccant dehydrators. (B) Report annual CO 2 and CH 4 emissions at the facility 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 lifts. Whether the selected well from the tubing diameter and pressure group combination had a plunger lift (yes/no).*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 111 of 151 (C) Cumulative number of unloadings vented to the atmosphere. (D) Average flow rate of the measured well venting in cubic feet per hour (refer to § 98.233(f)(1)(i)(A)). (E) Internal casing diameter or internal 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 psia, 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 Calculat ion Methodologies 2 and 3 (refer to Equation W
- 8 and W
- 9 of § 98.233), report the following for each sub
-basin category: (A) Count of wells vented to the atmosphere for liquids unloading. (B) Count of plunger lifts.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 112 of 151 (C) Cumulative number of unloadings vente d to the atmosphere. (D) Average internal casing diameter, in inches, for all wells, where applicable. (E) Report annual CO 2 and CH 4 emissions, expressed in metric tons CO 2 e for each GHG gas. (6) For well completions and workovers, report the following for each sub
-basin category: (i) For gas well completions and workovers with hydraulic fracturing by sub
-basin and well type (horizontal or vertical) combination (refer to Equation W
- 10A and W
- 10B of § 98.233), report the following: (A) Total count of completi ons in calendar year. (B) When using Equation W
- 10A, measured flow rate of backflow during well completion in standard cubic feet per hour. (C) Total count of workovers in calendar year that flare gas or vent gas to the atmosphere. (D) When using Equation W- 10A, measured flow rate of backflow during well workover in standard cubic feet per hour. (E) When using Equation W
- 10A, total number of days of backflow from all wells during completions. (F) When using Equation W
- 10A, total number of days of backflow f rom all wells during workovers.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 113 of 151 (G) Report number of completions employing purposely designed equipment that separates natural gas from the backflow and the amount of natural gas, in standard cubic feet, recovered using engineering estimate based on best 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 engineering estimate based on best available data. (I) Annua l CO 2 and CH 4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO 2 e for each gas. (J) Annual CO 2 , CH 4 , and N 2 O emissions that resulted from flares, expressed in metric tons CO 2 e for each gas. (ii) For gas well c ompletions 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 114 of 151 (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: (A) Total number of blowdowns for all unique physical volumes in the calenda r 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:*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 115 of 151 (i) For wellhead gas
- liquid separator with oil throughput greater than or equal to 10 barrels per day, using Calculation Methodology 1 and 2 of § 98.233(j), report the following by sub
basin category, unless otherwise specified: (A) Number of wellhead separ ators 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) Best 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. (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 control measures not at well pads, receiving your oil. (I) Range of concentrations of flash gas, CH 4 and CO 2 . (J) Annual CO 2 and CH 4 emissions that resu lted from venting gas to the atmosphere, expressed in metric tons CO 2 e for each gas, for all wellhead gas
- liquid separators or storage tanks*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 116 of 151 using Calculation Methodology 1, and for all wellhead gas
- liquid separators or storage tanks using Calculation Meth odology 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 separat ors or storage tanks using Calculation Methodology 2 of § 98.233(j). (L) Annual CO 2, CH 4, and N 2 O emissions that resulted from flaring gas, expressed in metric tons CO 2 e for each gas, for all wellhead gas
- liquid separators or storage tanks using Calculation Methodology 1, and for all wellhead gas
- liquid separators or storage tanks using Calculation Methodology 2 of § 98.233(j). (ii) For wells with oil production greater than or equal to 10 barrels per day, using Calculation Methodology 3 and 4 of § 98.233(j), report the following by sub
-basin category: (A) Total volume of sales oil from all wells in barrels per year. (B) Total number of wells sending oil directly to tanks. (C) Total number of wells sending oil to separators off the well pads.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 117 of 151 (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 hydrocarbon tanks on wellpads. (F) Count of hydrocarbon tanks, both on and off well pads assumed to have emissions control measures: either vapor recovery system or flaring of tank vapors. (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 f or each gas, at the sub
-basin level for Calculation Methodology 3 and 4 of § 98.233(j). (iii) For wellhead gas
- liquid separators and wells with throughput less than 10 barrels per day, using Calculation Methodology 5 of § 98.233(j) Equation W
- 15 of § 98.233, report the following: (A) Number of wellhead separators. (B) Number of wells without wellhead separators.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 118 of 151 (C) Total volume of oil production in barrels per year. (D) Best estimate of fraction of production sent to tanks with assumed control measures: eithe r vapor recovery system or flaring of tank vapors. (E) Count of hydrocarbon tanks on well pads. (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, expressed 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 Calculation Methodology 5 of § 98.233(j). (iv) If wellhead separator dump valve is functioning improperly during the calendar year (refer to Equation W
- 16 of § 98.233), report the following: (A) Count of wellhead separators that dump valve factor is applied. (B) Annual CO 2 and CH 4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO 2 e f or each*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 119 of 151 gas, at the sub
-basin level for improperly functioning dump valves. (9) For transmission tank emissions identified in § 98.233(k) from scrubber dump valves report the following: (i) For each vent stack, report annual CO 2 and CH 4 emissions that resul ted from venting gas directly to the atmosphere, expressed in metric tons CO 2 e for each gas. (ii) For each transmission storage tank, report annual CO 2 , CH 4 , and N 2 O emissions that resulted from flaring process gas from the transmission storage tank, expre ssed in metric tons CO 2 e for each gas. (iii) A unique name or ID number for the vent stack monitored according to 40 CFR 98.233(k). (10) For well testing venting and flaring (refer to Equation W
- 17A or W
- 17B of § 98.233), report the following: (i) Number of wells tested per basin in calendar year. (ii) Average gas to oil ratio for each basin. (iii) Average number of days the well is tested in a basin. (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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 120 of 151 (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 Equatio n 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) Average gas to oil ratio for each basin. (iii) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons CO 2 e for each gas, emissions from associated natural gas venting. (iv) Report 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 associated natural gas flaring. (12) For flare stacks (refer to Equation W
- 19, W
- 20, and W
21 of § 98.233), report the following for each flare: (i) Whether flare has a continuous flow monitor. (ii) Volume of gas sent to flare in cubic feet per year. (iii) Percent of gas sent to un
- lit flare determined by engineering estimate and process knowledge based on best available data and operating records. (iv) Whether flare has a continuous gas analyzer.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 121 of 151 (v) Flare combustion efficiency. (vi) Report uncombusted CH 4 emissions, in metric tons CO 2 e (refe r 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 combusted CO 2 emissions, in metric tons CO 2 e (refer to Equation W
- 21 of § 98.233). (ix) Report N 2 O emissions, in metric tons CO 2 e. (x) For the natural gas processing industry segment, a unique name or ID number for the flare stack. (xi) In the case that a CEMS is used to measure CO 2
emissions for the flare stack, indicate that a CEMS was used in the annual report and report the combusted CO 2 and uncombusted CO 2 as a combined number. (13) For each centrifugal 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 122 of 15 1 (D) Type of meters used for making measurements. (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 measur ed 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 blowdown vent emissions when in operating mode in metric tons of CO 2 e for each gas. (iii) For wet and dry seal centrifugal compressors in not operating, depressurized mode (refer to Equations W
- 22 through W- 24 of § 98.233), report the following: (A) Total time in hours the compressor is in shutdown, depressurized mode.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 123 of 151 (B) Reporter emission factor for isolation valve emissions in shutdown, depressurized mode in cubic feet per hour (refer to Equation W
- 24 of § 98.233). (C) Report the isolation valve leakage emissions in not operating, depressurized mode in metric tons of CO 2 e for each gas. (iv) Report total annual compressor emissions 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: (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) For reciprocating compressors rod packing emissions with or with out 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 124 of 151 (C) Report rod packing emissio ns for compressors measured and for compressors not measured in metric tons of CO 2 e for each gas. (ii) For reciprocating compressors blowdown vents not manifold to rod packing vents, in operating and standby pressurized mode (refer to Equations W
- 26 through W
- 28 of § 98.233), report the following: (A) Total time in hours the compressor is in standby, pressurized mode. (B) Reporter emission factor for blowdown vents in cubic feet per hour (refer to § 98.233, Equation W
- 28). (C) Report blowdown vent emissions when in operating and standby pressurized modes in metric tons of CO 2 e for each gas. (iii) For reciprocating compressors in not operating, depressurized mode (refer to Equations W
- 26 through W
- 28 of § 98.233), report the following: (A) Total time the compres sor is in not operating, depressurized mode. (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).*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 125 of 151 (C) Report isolation valve leakage emissions in not ope rating, 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
o nshore production) that uses emission factors for estimating emissions (refer to § 98.233(q) and (r)) (i) For equipment leaks found in each leak survey (refer to § 98.233(q)), report the following: (A) Total count of leaks found in each complete survey liste d by date of survey and each component type for which there is a leaker emission factor in Tables W
- 2, W
- 3, W
- 4, W
- 5, W
- 6, and W
- 7 of this subpart. (B) For onshore natural gas processing, range of concentrations of CH 4 and CO 2 (refer to Equation W
- 30A of § 98.233).*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 126 of 151 (C) Annual CO 2 and CH 4 emissions in metric tons CO 2 e for each gas (refer to Equation W
- 30A of § 98.233), by component type. (ii) For equipment leaks calculated using population counts and factors (refer to § 98.233(r)), report the following: (A) For source categories § 98.230(a)(5), (a)(6), and (a)(7), total count for each component type in Tables W
- 4, W
- 5, and W
- 6 of this subpart for which there is a population emission factor, listed by major heading and component type. (B) For onshore produc tion (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 over which all T
- D transfer stations will be monitored at least once. (iii) Number of T
- D stations monitored in calendar year. (iv) Total number of below grade T
- D transfer stations in the facility.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 127 of 151 (v) Total number of above grade metering
- regulating stations (this count will include above grade T
- D transfer stations) in the facility. (vi) T otal 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 for 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. (xii) Number of miles of cast iron distribution mains. (xiii) Number of unprotected steel distribution serv ices. (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 transfe r 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 128 of 151 (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 stations (including T
- D transfer stations) combined. (xxi) Annual CO 2 and CH 4 emissions, in metric tons CO 2 e for each gas, from all distribution mains combined. (xxii) Annual CO 2 and CH 4 emissions, in metric tons CO 2 e for each gas, from all distribution services combined. (17) For each EOR injection pump blowdown (refer to Equation W
- 37 of § 98.23 3), report the following: (i) Pump capacity, in barrels per day. (ii) Volume of critical phase gas between isolation valves. (iii) Number of blowdowns per year. (iv) Critical phase EOR injection gas density. (v) For each EOR pump, report annual CO 2 emissions , expressed in metric tons CO 2 e for each gas. (18) For EOR hydrocarbon liquids dissolved CO 2 for each sub
basin category (refer to Equation W
- 38 of § 98.233), report the following: (i) Volume of crude oil produced in barrels per year.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 129 of 151 (ii) Amount of CO 2 retained in hydrocarbon liquids in metric tons per barrel, under standard conditions. (iii) Report annual CO 2 emissions 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 emissions from external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, expressed in metric tons CO 2 e for each gas, by type of unit. (iv) Cumulative volume of fuel combusted in external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by fuel type. (v) Cumulative number of internal fuel combustion units, not compressor - drivers, with a rated heat capacity equal to or le ss than 1 mmBtu/hr or 130 horsepower, by type of unit.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 130 of 151 (vi) Report annual CO 2 , CH 4 , and N 2 O emissions from internal combustion units greater than 1mmBtu/hr, expressed in metric tons CO 2 e for each gas, by type of unit. (vii) Cumulative volume of fuel combus ted in internal combustion units with a rated heat capacity larger than 1 mmBtu/hr or 130 horsepower, by fuel type. (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 production, report the best available estimate of API gravity, best available estimate of gas to oil ratio, and best available estimate of average low pressure separator pr essure for each oil sub
-basin category. § 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 131 of 151 (d) Inputs and outputs of calculations or emissions computer model runs used for e ngineering estimation of emissions. (e) The records required under § 98.3(g)(2)(i) shall include an explanation of how company records, engineering estimation, or best available information are used to calculate each applicable parameter under this subpart. § 98 . 238 Definitions . Except as provided in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Acid gas means hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) contaminants that are separated from sour natural 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.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 132 of 151 Associated with a single well
-pad means associated with the hydrocarbon stream as produced from one or more wells located on that single well
-pad. The association ends where the stream from a single well
-pad is combined with streams from one or more additional single well
-pads, where the point of combination is lo cated 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, Number 10 (October 1991) (incorporated by reference,
see § 98.7) and the Alaska Geological Provin ce Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics 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 compound), metal to metal compression, or fluid barrier through which natural gas or liquid can escape to the atmosphere.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 133 of 151 Compressor means any machine for raising the pressure of a natural gas or CO 2 by drawing in low pressure natural gas or CO 2 and discharging significantly higher pressure natural gas or CO 2. Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, separated from na tural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at storage conditions. Distribution pipeline means a pipeline that is designated as such by the Pipeline and Hazardous Material Safety Administration (PHMSA) 49 CFR 192.3. Engineering estimation, for purposes of subpart W, means an estimate of emissions based on engineering principles applied to measured and/or approximated physical parameters such as dimensions of containment, actual pressures, actual temperatures, and compositions. Enhanced oil recovery (EOR) means the use of certain methods such as water flooding or gas injection into existing wells to increase the recovery of crude oil from a reservoir. In the context of this subpart, EOR applies to injectio n of critical phase or immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 134 of 151 Equipment leak means those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally
- equivalent opening. Equipment leak detection means the process of identifying emissions from equipment, components, and other point sources. External combustion means fired combustion in which the flame and products of combustion are separated from contact with the process fluid t o which the energy is delivered. Process fluids may be air, hot water, or hydrocarbons. External combustion equipment may include fired heaters, industrial boilers, and commercial and domestic combustion units. Facility with respect to natural gas distribu tion for purposes of reporting under this subpart and for the corresponding subpart A requirements means the collection of all distribution pipelines and metering
- regulating stations that are operated by a Local Distribution Company (LDC) within a single
s tate 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 subpa rt and for the corresponding subpart A requirements means the collection of all distribution pipelines and metering
- regulating stations that are*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 135 of 151 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 correspondin g subpart A requirements means all petroleum or natural gas equipment on a single well
-pad or associated with a single well
-pad and CO 2 e OR operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petroleum and natural gas production owner or operator and that are located in a single hydrocarbon basin as defined in § 98.238 . Where a person or entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility. 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). Field means oil and gas fields identified in the United States as defined by the Energy Information Administration Oil*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 136 of 151 and Gas Field Code Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see § 98.7). Flare, for the purposes of subpart W, means a combustion device, whether at ground level or elevated, that uses an open or closed 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 hydroc arbons 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 refrigeratio n, 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 amb ient temperature or heated above ambient temperatures, or the*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 137 of 151 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 deviation from primarily vertical to a primarily horizontal inclination or declination tracking in parallel with and through the target formation. Internal combustion means the combustion of a fuel that occurs with an oxidizer (usually air) in a combustion chamber. 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 distance, generating useful mechanical energy. Internal combustion equipment may include gasoline and diesel industrial engines, natural gas
- fired reciprocating engines, and gas turbines. Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by reducing its temperature to

- 260 degrees Fahrenheit at atmospheric pressure. LNG boil
- off gas means natural gas in the gaseous phase that vents from LNG storage tanks due to ambient heat leakage*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 138 of 151 through the tank insulation and hea t energy dissipated in the LNG by internal pumps. Meter/regulator run means a series of components used in regulating pressure or metering natural gas flow or both. Metering
- regulating station means a station that meters the flowrate, regulates the pressur e, or both, of natural gas in a natural gas distribution facility. This does not include customer meters, customer regulators, or farm taps. Natural gas means a naturally occurring mixture or process derivative of hydrocarbon and non
- hydrocarbon gases foun d in geologic formations beneath the earth's surface, of which its constituents include, but are not limited to, methane, heavier hydrocarbons and carbon dioxide. Natural gas may be field quality, pipeline quality, or process gas. Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act. Onshore petroleum and natural gas production owner or operator means the person or entity who holds the permit to operate petroleum and natural gas wells on the drilling permit*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 139 of 151 or an operating permit wher e no drilling permit is issued, which operates an onshore petroleum and/or natural gas production facility (as described in § 98.230(a)(2). Where petroleum and natural gas wells operate without a drilling or operating permit, the person or entity that pays the State or Federal business income taxes is considered the owner or operator. Operating pressure means the containment pressure that characterizes the normal state of gas or liquid inside a particular process, pipeline, vessel or tank. Pressure groups as applicable to each sub
-basin are defined as follows: Less than or equal to 25 psig; greater than 25 psig and less than or equal to 60 psig; greater than 60 psig and less than or equal to 110 psig; greater than 110 psig and less than or equal to 200 psig; and greater than 200 psig. The pressure in the context of pressure groups is either the well shut
- in pressure; 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. Pump means a device used to raise pressure, drive, or increase flow of liquid streams in closed or open conduits. Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon dioxide containing light liquids from escaping the inside of a pump case to the atmosphere.*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 140 of 151 Pump seal emissions means hydrocarbon gas released from the seal face between the pump internal chamber and the atmosphere. Reservoir means a porous and permeable underground natural formation cont aining significant quantities of hydrocarbon liquids and/or gases. 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
su ch that it meets the specifications set by a pipeline transmission company, and/or a distribution company; and the compressors operated by the processing facility, whether inside the processing facility boundary fence or outside the fence
line, that delive r the residue gas from the processing facility 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 reservoir*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 141 of 151 rock. The distinction between high permeability gas and tight gas reservoirs shall be designated as follows: High permeability gas reservoirs with >0.1 millidarcy permeability, and tight gas reservoirs with ≤0.1 millidarcy permeability. Permeability for a reservoir type shall be determined by engineering estimate. Wells that produce from high permeability gas, shale gas, coal seam, or other tight reservoir rock are considered gas wells; gas wells producing fr om 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 wells that produce hydrocarbon liquids and do not meet the definiti on of a gas well in this sub
-basin category definition are considered to be in the oil formation. All emission sources that handle condensate from gas wells in high permeability gas, shale gas, or tight reservoir rock formations are considered to be in the formation that the gas well belongs to and not in the oil formation. Transmission
- distribution (T
- D) transfer station means a metering
- regulating station where a local distribution company takes part or all of the natural gas from a transmission pipeline and puts it into a distribution pipeline. Transmission pipeline means a Federal Energy Regulatory Commission rate
- regulated Interstate pipeline, a state rate
-*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 142 of 151 regulated Intrastate pipeline, or a pipeline that falls under the “Hinshaw Exemption” as reference d in section 1(c) of the Natural Gas Act, 15 U.S.C. 717
- 717 (w)(1994). Tubing diameter groups are defined as follows: Outer diameter less than or equal to 1 inch; outer diameter greater than 1 inch and less than 2.375 inch; and outer diameter greater than or equal to 2.375 inch. Tubing systems means piping equal to or less than one half inch diameter as per nominal pipe size. Turbine meter means a flow meter in which a gas or liquid flow rate through the calibrated tube spins a turbine from which the spin r ate is detected and calibrated to measure the fluid flow rate. Vented emissions means intentional or designed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process designed flow t o the atmosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas used to power equipment (such as pneumatic devices). Vertical well means a well bore that is primarily vertical but has some unintentional deviation or one or more intentional deviations to enter one or more subsurface targets that are off
-*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 143 of 151 set horizontally from the surface location, intercepting the targets either vertically or at an angle. Well testing venting and flaring means venting and/or flaring of natural gas at the time the production rate of a well is determined for regulatory, commercial, or technical purposes. If well testing is conducted immediately after well completion or workover, then it is considered part of well completion or workover . [75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80590, Dec. 23, 2011] **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 (s**  **cf/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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 144 of 151 **Onshore petroleum and natural gas production**  **Emission factor (s**  **cf/hour/component)** 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 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 145 of 151

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 greate r than or equal to 20°API are considered “light crude.” 5 “Others” category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents. 6 Hydrocarbon liquids less than 20°API are considered “heavy crude.” **Table W -**  **1B to Subpart W of Part 98 —**  **Default Average Component Counts for Major Onshore Natural Gas Production Equipment**  **Major equipment Valves**  **Connectors Open**  **- ended lines**  **Pressure relief valves**  **Eastern U.S.** Wellheads 8 38 0.5 0 Separators 1 6 0 0 Meters/piping 12 45 0 0 Compressors 12 57 0 0 In - line heaters 14 65 2 1 Dehydrators 24 90 2 2 **Western U.S.** Wellheads 11 36 1 0 Separators 34 106 6 2 Meters/piping 14 51 1 1 Compressors 73 179 3 4 In - line heaters 14 65 2 1 Dehydrators 24 90 2 2

**Table W -**  **1C to Subpart W of Part 98 —**  **Default Average Component Counts For Major Crude Oil Production Equipment**  **Major equipment Valves**  **Flanges Connectors**  **Open -**  **ended lines**  **Other**

**components Eastern U.S.**  Wellhead **5 10**  **4 0**  **1** Separator **6 12**  **10 0**  **0*******DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 146 of 151
**Major equipment Valves**  **Flanges Connectors**  **Open -**  **ended lines**  **Other**

**components** Heater - treater **8 12**  **20 0**  **0** Header **5 10**  **4 0**  **0 Western U.S.**  Wellhead **5 10**  **4 0**  **1** Separator **6 12**  **10 0**  **0** Heater - treater **8 12**  **20 0**  **0** Header **5 10**  **4 0**  **0**

**Table W -**  **1D of Subpart W of Part 98 —**  **Designation o** **f 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 147 of 151
**Eastern U.S. Western U.S.**  Vermont Oregon Virginia South Dakota West Virginia Texas Wisconsin Utah Washington Wyoming

**Table W -**  **2 of Subpart W of Part 98 —**  **Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Processing** 

**Onshore natural gas processing plants Emission factor**  **(scf/hour/component) Leaker Emission Factors** **— Compressor Components, Gas Service** 

Valve 1 14.84 Connector 5.59 Open
- Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 **Leaker Emission Factors —**  **Non -**  **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/hou** **r/component) Leaker Emission Factors** **— Compressor Components, Gas Service** 

Valve 1 14.84*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 148 of 151
**Onshore natural gas transmission compression Emission factor**  **(scf/hou r/component)**  Connector 5.59 Open
- Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 **Leaker Emission Factors —**  **Non -**  **Compressor Components, Gas Service** Valve 1 6.42 Connector 5.71 Open
- Ended Line 11.27 Pressure Relief Valve 2.01 Meter 2.93 **Population Emission Factors —** **Gas Service**

Low Continuous Bleed Pneumatic Device Vents 2 1.37 High Continuous Bleed Pneumatic Device Vents 2 18.20
Intermittent Bleed Pneumatic Device Vents 2 2.35

1 Valves include control valves, block valves and 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*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 149 of 151
**Underground natural gas storage**  **Emission factor (scf/hour/component)**  Pressure Relief Valve 0.17 Open Ended Line 0.03 **Population Emission Factors —**  **Other Components, Gas Service** Low Continuous Bleed Pneumatic Device Vents 2 1.37 High Continuous Bleed Pneumatic Device Vents 2 18.20
Intermittent Bleed Pneumatic Device Vents 2 2.35

1 Valves include control valves, block valves and regulator valves. 2 Emission Factor is in units of “scf/hour/device.”

**Table W -**  **5 of Subpart W of Part 98 —**  **Default Methane Emission Factors for Liquefied Nat** **ural Gas (LNG) Storage**

**LNG storage Emission factor (scf/hour/component)**  **Leaker Emission Factors —** **LNG Storage Components, LNG Service**

Valve 1.19 Pump Seal 4.00 Connector 0.34 Other 1 1.77 **Population Emission Factors —** **LNG Storage Compressor, Gas Service**

Vapor Recovery Compressor 2 4.17 1 “Other” equipment type should be applied for any equipment type other than connectors, pumps, or valves. 2 Emission Factor is in units of “scf/hour/device.”

**Table W -**  **6 of Subpart W of Part 98 —**  **Default Methane Emission Factors for LNG Import and Export Equipment**  **LNG import and export equipment Emission factor (scf/hour/component)**  **Leaker Emission Factors —** **LNG Terminals Components, LNG Service**

Valve 1.19 Pump Seal 4.00 Connector 0.34*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 150 of 151
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 Cast Iron 27.25 **Population Emission Factors —**  **Distribution Services, Gas Service 4**  Unprotected Steel 0.19 Protected Steel 0.02*****DRAFT DELIBERATIVE –**  **DO NOT CITE OR QUOTE -**  **This file has not been formatted or copyedited to meet**  **Federal Register style** *** Page 151 of 151
**Natural gas distribution Emission factor (scf/hour/**  **component)** 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.”