NA
                                                                             NA
                                                                             NA
                                                                             NA
BC3F8
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                            Remote Plasma Cleaning:
1-Ui
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                          0.063
                                                                             NA
                                                                          0.018
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
BCF4
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                          0.038
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
BC2F6
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
BC3F8
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
BCHF3
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                       0.000059
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
BCH2F2
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                         0.0016
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
BCH3F
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                         0.0028
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                           In Situ Thermal Cleaning:
1-Ui
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                           0.28
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
BCF4
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                          0.010
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
BC2F6
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
BC3F8
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA
                                                                             NA

Subpart N -- Glass Production
 Amend § 98.146 by revising paragraphs (a)(2) and (b)(3) to read as follows:
§ 98.146 Data reporting requirements.
*	*	*	*	*
(a) *	*	*
(2) Annual quantity of glass produced (tons), by glass type, from each continuous glass melting furnace and from all furnaces combined.
(b) *	*	*
(3) Annual quantity of glass produced (tons), by glass type, from each continuous glass melting furnace and from all furnaces combined.
*	*	*	*	*
 Amend § 98.147 by revising paragraphs (a)(1) and (b)(1) to read as follows:
§ 98.147 Records that must be retained.
*	*	*	*	*
(a) *	*	*
(1) Monthly glass production rate for each continuous glass melting furnace, by glass type (tons).
*	*	*	*	*
(b) *	*	*
(1) Monthly glass production rate for each continuous glass melting furnace, by glass type (metric tons).
*	*	*	*	*
Subpart P -- Hydrogen Production
 Amend § 98.163 by revising the introductory text and paragraph (b) introductory text and adding paragraph (d) to read as follows:
§ 98.163 Calculating GHG emissions.
You must calculate and report the annual CO2 emissions from each hydrogen production process unit using the procedures specified in paragraphs (a) through (d) of this section, as applicable.
*	*	*	*	*
(b) Fuel and feedstock material balance approach. Calculate and report CO2 emissions as the sum of the annual emissions associated with each fuel and feedstock used for hydrogen production by following paragraphs (b)(1) through (3) of this section. Adjust the emissions estimated using paragraphs (b)(1) through (b)(3) by correcting for non-CO2 carbon produced, if applicable, according to paragraph (d) of this section. The carbon content and molecular weight shall be obtained from the analyses conducted in accordance with § 98.164(b)(2), (b)(3), or (b)(4), as applicable, or from the missing data procedures in § 98.165. If the analyses are performed annually, then the annual value shall be used as the monthly average. If the analyses are performed more frequently than monthly, use the arithmetic average of values obtained during the month as the monthly average.
*	*	*	*	*
(d) If carbon other than CO2 is collected and transferred off site or if methanol is intentionally produced as a desired product, you must correct the CO2 emissions determined in paragraph (b) of this section to determine the net CO2 emissions according to Equation P-4 of this section.
	CO2,net=p=13CO2,p-4412n=1kCoffsite,n-4432n=1kMeOHn	(Eq.P-4)
CO2,net	=	Annual net CO2 process emissions from hydrogen production unit (metric tons/yr).
CO2,p	=	Annual CO2 process emissions arising from fuel and feedstock consumption based on fuel type "p" (metric tons/yr).
p	=	index for fuel or feedstock type; 1 indicates gaseous fuel or feedstocks; 2 indicates liquid fuel or feedstocks; and 3 indicates solid fuel or feedstocks
Coffsite,n	=	Mass of carbon other than CO2 or methanol collected from the hydrogen production unit and transferred off site, from company records for month n (metric tons carbon).
MeOHn	=	Mass of methanol intentionally produced as a desired product from the hydrogen production unit, from company records for month n (metric tons). If the methanol product has a 99.5 weight percent or higher purity, use the mass of methanol product produced; otherwise, you must correct that mass of product produced by the methanol purity (determined from company records) to determine the mass of methanol intentionally produced.
k	=	Months in the year.
44/12	=	Ratio of molecular weights, CO2 to carbon.
44/32	=	Ratio of molecular weights, CO2 to methanol.
 Amend § 98.164 by revising paragraphs (b)(2) through (4) and (b)(5) introductory text and adding paragraph (b)(5)(xix) to read as follows:
§ 98.164 Monitoring and QA/QC requirements.
*	*	*	*	*
(b) *	*	*
(2) Determine the carbon content and the molecular weight annually of standard gaseous hydrocarbon fuels and feedstocks having consistent composition (e.g., natural gas) using the applicable methods in paragraph (b)(5) of this section. For non-hydrocarbon gaseous fuels and feedstocks that have a maximum product specification for carbon content less than or equal to 0.00002 kg carbon per kg of gaseous fuel or feedstock, you may determine the carbon content and the molecular weight annually using the product specification's maximum carbon content and molecular weight rather than using the methods specified in paragraph (b)(5) of this section. For other gaseous fuels and feedstocks (e.g., biogas, refinery gas, or process gas), sample and analyze no less frequently than weekly to determine the carbon content and molecular weight of the fuel and feedstock using the applicable methods in paragraph (b)(5) of this section.
(3) Determine the carbon content of fuel oil, naphtha, and other liquid fuels and feedstocks at least monthly, except annually for standard liquid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for liquid fuels and feedstocks delivered by bulk transport (e.g., by truck or rail) using the applicable methods in paragraph (b)(5) of this section. For non-hydrocarbon liquid fuels and feedstocks that have a maximum product specification for carbon content less than or equal to 0.00006 kg carbon per gallon of liquid fuel or feedstock, you may determine the carbon content annually using the product specification's maximum carbon content rather than using the methods specified in paragraph (b)(5) of this section.
(4) Determine the carbon content of coal, coke, and other solid fuels and feedstocks at least monthly, except annually for standard solid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for solid fuels and feedstocks delivered by bulk transport (e.g., by truck or rail) using the applicable methods in paragraph (b)(5) of this section.
(5) Except as provided in paragraphs (b)(2) and (b)(3) for certain non-hydrocarbon feedstocks, you must use the following applicable methods to determine the carbon content for all fuels and feedstocks, and molecular weight of gaseous fuels and feedstocks. Alternatively, you may use the results of chromatographic analysis of the fuel and feedstock, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the chromatograph are documented in the written monitoring plan for the unit under § 98.3(g)(5).
*	*	*	*	*
(xix) For non-hydrocarbon fuels and feedstocks, if the methods listed in paragraphs (b)(5)(i) through (b)(5)(xviii) of this section are not appropriate because the relevant compounds cannot be detected, the quality control requirements are not technically feasible, or use of the method would be unsafe, you may use modifications of the methods listed in paragraphs (b)(5)(i) through (b)(5)(xviii) or use other methods that are applicable to your fuel or feedstock.
 Amend § 98.166 by revising the introductory text and paragraphs (b)(1) and (d) to read as follows:
§ 98.166 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraph (a) or (b) of this section, as appropriate, and paragraphs (c) through (e) of this section:
*	*	*	*	*
(b) *	*	*
(1) Unit identification number and annual CO2 emissions (determined in accordance with § 98.163(b) or (d), as applicable).
*	*	*	*	*
(d) Annual quantity of carbon other than CO2 collected and transferred off site in either gas, liquid, or solid forms (metric tons carbon), excluding methanol, for each process unit.
*	*	*	*	*
 Amend § 98.167 by revising paragraphs (b) and (e) introductory text and adding paragraphs (e)(13) and (14) to read as follows:
§ 98.167 Records that must be retained.
*	*	*	*	*
(b) If a CEMS is not used to measure CO2 emissions, then you must retain records of all analyses and calculations conducted to determine the values reported in § 98.166(b) through (e).
*	*	*	*	*
(e) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (e)(1) through (14) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (e)(1) through (14) of this section for each hydrogen production unit.
*	*	*	*	*
(13) Monthly mass of carbon other than CO2 or methanol collected and transferred off site (metric tons carbon) (Equation P-4).
(14) Monthly mass of methanol intentionally produced as a desired product (metric tons) (Equation P-4).

Subpart Q -- Iron and Steel Production
 Amend § 98.173 by revising Equation Q-5 in paragraph (b)(1)(v) to read as follows:
§ 98.173 Calculating GHG emissions.
*	*	*	*	*
(b) *	*	*
(1) *	*	*
(v) *	*	*
CO2= 4412* Iron*Ciron+Scrap*Cscrap+Flux*CFlux+Electrode*CElectrode+Carbon*CCarbon-Steel*CSteel+Fg* Cgf* MWMVC*0.001-Slag*CSlag-R*CR	(Eq. Q-5)
*	*	*	*	*
 Amend § 98.174 by:
a. Revising paragraph (b)(2) introductory text;
b. Redesignating paragraph (b)(2)(vi) as paragraph (b)(2)(vii); and
c. Adding new paragraph (b)(2)(vi).
The revisions and addition read as follows:
§ 98.174 Monitoring and QA/QC requirements.
*	*	*	*	*
(b) *	*	*
(2) Except as provided in paragraph (b)(4) of this section, determine the carbon content of each process input and output annually for use in the applicable equations in § 98.173(b)(1) based on analyses provided by the supplier, analyses provided by material recyclers who manage process outputs for sale or use by other industries, or by the average carbon content determined by collecting and analyzing at least three samples each year using the standard methods specified in paragraphs (b)(2)(i) through (b)(2)(vii) of this section as applicable.
*	*	*	*	*
(vi) ASTM E415-17, Standard Test Method for Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission Spectrometry (incorporated by reference, see § 98.7) as applicable for steel.
*	*	*	*	*
 Amend § 98.176 by revising paragraphs (e)(2) and (g) to read as follows:
§ 98.176 Data reporting requirements.
*	*	*	*	*
(e) *	*	*
(2) Whether the carbon content was determined from information from the supplier, material recycler, or by laboratory analysis, and if by laboratory analysis, the method used in § 98.174(b)(2).
*	*	*	*	*
(g) For each unit, the type of unit, the annual production capacity, and annual operating hours.
*	*	*	*	*

Subpart S -- Lime Manufacturing
 Amend § 98.193 by revising paragraph (b)(2)(iv) to read as follows:
§ 98.193 Calculating GHG emissions.
*	*	*	*	*
	(b) *	*	*
	(2) *	*	*
(iv) You must calculate annual net CO2 process emissions for all lime kilns using Equation S-4 of this section:
    ECO2, net= i=1tn=112EFLIME,i,n* MLIME,i,n+ i=1bn=112EFLKD,i,n* MLKD,i,n+ i=1zEwaste,i - n=112Eproduct,n
	(Eq. S-4)
Where:
ECO2, net	=	Annual net CO2 process emissions from lime production from all lime kilns (metric tons/year).
EFLIME,i,n	=	Emission factor for lime type i produced, in calendar month n (metric tons CO2/ton lime) from Equation S-1 of this section.
MLIME,i,n	=	Weight or mass of lime type i produced in calendar month n (tons).
EFLKD,i,n	=	Emission factor of calcined byproducts or wastes sold for lime type i in calendar month n, (metric tons CO2/ton byproduct or waste) from Equation S-2 of this section.
MLKD,i,n	=	Monthly weight or mass of calcined byproducts or waste sold (such as lime kiln dust, LKD) for lime type i in calendar month n (tons).
Ewaste,i	=	Annual CO2 emissions for calcined lime byproduct or waste type i that is not sold (metric tons CO2) from Equation S-3 of this section.
Eproduct,n	=	Monthly amount of CO2 from lime production that is captured for use in all on-site processes in calendar month n, as described in § 98.196(b)(17) (metric tons).
t	=	Number of lime types produced
b	=	Number of calcined byproducts or wastes that are sold.
z	=	Number of calcined byproducts or wastes that are not sold.
*	*	*	*	*
 Amend § 98.196 by:
a. Revising paragraph (a) introductory text;
b. Adding paragraphs (a)(9) through (14);
c. Revising paragraphs (b) introductory text, (b)(1), (b)(17) introductory text, and (b)(17)(i); and
d. Adding paragraphs (b)(22) and (23).
The revisions and additions read as follows:
§ 98.196 Data reporting requirements.
*	*	*	*	*
(a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart the relevant information required by § 98.36 and the information listed in paragraphs (a)(1) through (14) of this section.
*	*	*	*	*
(9) Annual arithmetic average of calcium oxide content for each type of lime product produced (metric tons CaO/metric ton lime).
(10) Annual arithmetic average of magnesium oxide content for each type of lime product produced (metric tons MgO/metric ton lime).
(11) Annual arithmetic average of calcium oxide content for each type of calcined lime byproduct/waste sold (metric tons CaO/metric ton lime).
(12) Annual arithmetic average of magnesium oxide content for each type of calcined lime byproduct/waste sold (metric tons MgO/metric ton lime).
(13) Annual arithmetic average of calcium oxide content for each type of calcined lime byproduct/waste not sold (metric tons CaO/metric ton lime).
(14) Annual arithmetic average of magnesium oxide content for each type of calcined lime byproduct/waste not sold (metric tons MgO/metric ton lime).
 (b) If a CEMS is not used to measure CO2 emissions, then you must report the information listed in paragraphs (b)(1) through (23) of this section.
(1) Annual net CO2 process emissions from all lime kilns combined (metric tons).
*	*	*	*	*
(17) Indicate whether CO2 was captured and used on-site (e.g., for use in a purification process, the manufacture of another product). If CO2 was captured and used on-site, provide the information in paragraphs (b)(17)(i) and (ii) of this section.
(i) The annual amount of CO2 captured for use in all on-site processes.
*	*	*	*	*
(22) Annual average results of chemical composition analysis of all lime byproducts or wastes not sold.
(23) Annual quantity (tons) of all lime byproducts or wastes not sold.
 Amend § 98.197 by revising paragraph (c) introductory text and adding paragraph (c)(10) to read as follows:
§ 98.197 Records that must be retained.
*	*	*	*	*
(c) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) through (10) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (10) of this section.
*	*	*	*	*
(10) Monthly amount of CO2 from lime production that is captured for use in all on-site processes, as described in § 98.196(b)(17) (metric tons) (Equation S-4).

Subpart W -- Petroleum and Natural Gas Systems
 Amend § 98.230 by revising paragraph (a)(3) to read as follows:
§ 98.230 Definition of the source category.
(a) *	*	*
(3) Onshore natural gas processing. Natural gas processing means the forced extraction of natural gas liquids (NGLs) from field gas, fractionation of mixed NGLs to natural gas products, or both. Natural gas processing does not include a Joule-Thomson valve, a dew point depression valve, or an isolated or standalone Joule-Thomson skid. This segment also includes all residue gas compression equipment owned or operated by the natural gas processing plant.
*	*	*	*	*
 Amend § 98.232 by:
a. Revising paragraphs (b) and (c)(21);
b. Adding paragraph (c)(23);
c. Revising paragraph (d)(7);
d. Adding paragraphs (d)(8) and (9);
e. Revising paragraph (e)(8);
f. Adding paragraph (e)(9);
g. Revising paragraphs (f)(6) and (8);
h. Adding paragraph (f)(9);
i. Revising paragraphs (g)(6) and (7);
j. Adding paragraph (g)(8);
k. Revising paragraphs (h)(7) and (8);
l. Adding paragraphs (h)(9) and (10) and (i)(8);
m. Revising paragraph (j)(10);
n. Adding paragraph (j)(13); and
o. Revising paragraph (m).
The revisions and additions read as follows:
§ 98.232 GHGs to report.
*	*	*	*	*
(b) For offshore petroleum and natural gas production, report CO2, CH4, and N2O emissions from equipment leaks, vented emission, and flare emission source types as identified in the data collection and emissions estimation study conducted by BOEM in compliance with 30 CFR 550.302 through 304 and CO2 and CH4 emissions from other large release events. Offshore platforms do not need to report portable emissions.
(c) *	*	*
(21) Equipment leaks listed in paragraph (c)(21)(i) or (ii) of this section, as applicable:
(i) Equipment leaks from components including valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components listed in paragraph (c)(11) or (19) of this section, and it does not include thief hatches or other openings on a storage vessel).
(ii) Equipment leaks from major equipment including wellheads, separators, meters/piping, compressors, acid gas removal units, dehydrators, heater treaters, and storage vessels.
*	*	*	*	*
(23) Other large release events.
(d) *	*	*
(7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters, and equipment leaks from all other components in gas service that either are subject to [reference to equipment leak standards for processing plants in 40 CFR part 60, subpart OOOOb] or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(8) Natural gas pneumatic device venting.
(9) Other large release events.
(e) *	*	*
(8) Equipment leaks from all other components that are not listed in paragraph (e)(1), (2), or (7) of this section and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, or that you elect to survey using a leak detection method described in § 98.234(a). The other components subject to this paragraph (e)(8) also do not include thief hatches or other openings on a storage vessel.
(9) Other large release events.
(f) *	*	*
(6) Equipment leaks from all other components that are associated with storage stations, are not listed in paragraph (f)(1), (2), or (5) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
*	*	*	*	*
(8) Equipment leaks from all other components that are associated with storage wellheads, are not listed in paragraph (f)(1), (2), or (7) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a, of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(9) Other large release events.
(g) *	*	*
(6) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(7) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(8) Other large release events.
(h) *	*	*
(7) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(8) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a).
(9) Acid gas removal vents.
(10) Other large release events.
(i) *	*	*
(8) Other large release events.
(j) *	*	*
(10) Equipment leaks listed in paragraph (j)(10)(i) or (ii) of this section, as applicable:
(i) Equipment leaks from components including valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components in paragraph (j)(8) or (9) of this section, and it does not include thief hatches or other openings on a storage vessel).
(ii) Equipment leaks from major equipment including wellheads, separators, meters/piping, compressors, acid gas removal units, dehydrators, heater treaters, and storage vessels.
*	*	*	*	*
(13) Other large release events.
*	*	*	*	*
(m) For onshore natural gas transmission pipeline, report pipeline blowdown CO2 and CH4 emissions from blowdown vent stacks and CO2 and CH4 emissions from other large release events.
 Amend § 98.233 by:
a. Revising paragraphs (a), (c), (d) introductory text, and (d)(4)(vi);
b. Adding paragraph (d)(12);
c. Revising paragraphs (e) introductory text, (e)(1) introductory text; (e)(1)(x), and (e)(2) introductory text;
d. Revising parameter "Count" of Equation W-5 in paragraph (e)(2);
e. Removing paragraphs (e)(3) and (4);
f. Reserving paragraph (e)(3);
g. Redesignating paragraphs (e)(5) and (6) as (e)(4) and (5), respectively;
h. Revising newly redesignated paragraphs (e)(4) and (5) and paragraphs (g)(4), (h)(2), (i) introductory text, and (i)(2) introductory text;
i. Revising parameters "Ta" and "Pa" of Equation W-14A in paragraph (i)(2)(i);
j. Revising parameters "Ta,p", "Pa,b,p", and "Pa,e,p" of Equation W-14B in paragraph (i)(2)(i);
k. Adding paragraph (i)(2)(iv);
l. Revising paragraphs (j) introductory text, (j)(1) introductory text, (j)(1)(iii), (iv), and (vii), and (j)(2);
m. Revising parameter "Count" of Equation W-15 in paragraph (j)(3);
n. Revising paragraphs (j)(4) through (6), (k)(5), (l)(6), and (m)(3) introductory text;
o. Revising parameters "Vp,q" and "SGp,q" of Equation W-18 in paragraph (m)(3);
p. Revising paragraphs (m)(5), (n) introductory text, (n)(1), (n)(2) introductory text, and (n)(5);
q. Removing and reserving paragraph (n)(9);
r. Revising paragraphs (o) introductory text, (o)(1)(i) introductory text, (o)(1)(i)(A) through (C), (o)(2) introductory text, (o)(2)(i) introductory text, and (o)(2)(ii);
s. Adding paragraph (o)(2)(iii);
t. Removing and reserving paragraph (o)(4)(ii)(D);
u. Revising paragraphs (o)(4)(ii)(E) and (o)(6)(i) introductory text;
v. Revising parameter "m" of Equation W-21 in paragraph (o)(6)(i);
w. Revising paragraph (o)(6)(ii) introductory text;
x. Revising parameter "m" of Equation W-22 in paragraph (o)(6)(ii);
y. Revising paragraph (o)(6)(iii) introductory text;
z. Revising parameter "m" of Equation W-23 in paragraph (o)(6)(iii);
aa. Revising parameter "Tg" of Equation W-24B in paragraph (o)(8);
bb. Revising paragraph (o)(10) introductory text;
cc. Revising parameter "Count" of Equation W-25 in paragraph (o)(10);
dd. Revising paragraphs (p) introductory text, (p)(1)(i), (p)(2) introductory text, (p)(2)(ii) introductory text, (p)(2)(ii)(C), (p)(2)(iii)(A), and (p)(4)(ii)(C);
ee. Removing and reserving paragraph (p)(4)(ii)(D);
ff. Revising paragraphs (p)(4)(ii)(E), (p)(6)(ii) introductory text, (p)(6)(iii) introductory text, and (p)(10) introductory text;
gg. Revising parameter "Count" of Equation W-29D in paragraph (p)(10);
hh. Revising paragraphs (q) introductory text and (q)(1) and the introductory text of paragraph (q)(2) introductory text;
ii. Revising parameter "EFs,p" of Equation W-30 in paragraph (q)(2) introductory text;
jj. Revising paragraphs (q)(2)(i), (iii), (v), (x), and (xi);
kk. Adding paragraph (q)(3);
ll. Revising the introductory text of paragraph (r) introductory text;
mm. Revising parameters "Es,e,I," "Es,MR,I," "Counte," "CountMR," and "EFs,e" of Equations W-32A and W-32B in paragraph (r) introductory text;
nn. Revising paragraphs (r)(2), (r)(6)(i) and (ii), and (s);
oo. Revising parameter "Za" of Equation W-34 in paragraph (t)(2);
pp. Removing the unnumbered text "You may use either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure conditions." after parameter "Za" of Equation W-34 in paragraph (t)(2); and
qq. Revising paragraphs (u)(2)(ii), (y), and (z).
The revisions and additions read as follows:
§ 98.233 Calculating GHG emissions.
*	*	*	*	*
(a) Natural gas pneumatic device venting. For all natural gas pneumatic devices at onshore natural gas processing facilities, onshore natural gas transmission compression facilities, and underground natural gas storage facilities, use methods specified in paragraphs (a)(1) through (5) of this section to calculate CH4 and CO2 emissions. For all continuous high bleed and continuous low bleed natural gas pneumatic devices at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility, use methods specified in paragraphs (a)(1) through (5) of this section to calculate CH4 and CO2 emissions. For intermittent bleed natural gas pneumatic devices at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility that are subject to monitoring requirements in part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, use the methods specified in paragraph (a)(6) of this section to calculate CH4 and CO2 emissions from those pneumatic devices. For intermittent bleed natural gas pneumatic devices at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility that are not subject to monitoring requirements in part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you may either elect to monitor your intermittent bleed natural gas pneumatic devices at least annually following the methods specified in part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, as applicable, and use the methods specified in paragraph (a)(6) of this section to calculate CH4 and CO2 emissions from your natural gas intermittent bleed pneumatic devices or use the methods specified in paragraphs (a)(1) through (5) of this section to calculate CH4 and CO2 emissions from your natural gas intermittent bleed pneumatic devices.
(1) Calculate CH4 and CO2 volumetric emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices using Equation W-1A of this section.
		(Eq. W-1A)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions in standard cubic feet per year from natural gas pneumatic device vents, of types "t" (continuous high bleed, continuous low bleed, intermittent bleed), for GHGi.
Countt	=	Total number of natural gas pneumatic devices of type "t" (continuous high bleed, continuous low bleed, intermittent bleed) as determined in paragraph (a)(1) or (a)(2) of this section.
EFt	=	Population emission factors for natural gas pneumatic device vents (in standard cubic feet per hour per device) of each type "t" listed in Tables W-1A, W-2B, W-3B, and W-4B to this subpart for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting, onshore natural gas processing, onshore natural gas transmission compression, and underground natural gas storage facilities, respectively.
GHGi	=	For onshore petroleum and natural gas production facilities, onshore petroleum and natural gas gathering and boosting facilities, onshore natural gas processing, onshore natural gas transmission compression facilities, and underground natural gas storage facilities, concentration of GHGi, CH4 or CO2, in produced natural gas or processed natural gas for each facility as specified in paragraphs (u)(2)(i) through (iv) of this section.
Tt	=	Average estimated number of hours in the operating year the devices, of each type "t", were in service (i.e., supplied with natural gas) using engineering estimates based on best available data. Default is 8,760 hours.
(2) For all industry segments, determine "Countt" for Equation W-1A of this subpart for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) by counting the devices, except as specified in paragraph (a)(3) of this section. The reported number of devices must represent the total number of devices for the reporting year.
(3) For the onshore petroleum and natural gas production industry segment, you have the option in the first two consecutive calendar years to determine "Countt" for Equation W-1A of this section for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) using engineering estimates based on best available data. For the onshore petroleum and natural gas gathering and boosting industry segment, you have the option in the first two consecutive calendar years to determine "Countt" for Equation W-1A for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) using engineering estimates based on best available data.
(4) For all industry segments, determine the type of pneumatic device using engineering estimates based on best available information.
(5) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
(6) Calculate CH4 and CO2 volumetric emissions using Equation W-1B of this section from natural gas intermittent bleed pneumatic devices that are monitored according to the requirements in this paragraph (a)(6).
          Ei=GHGi*24.1*z=1xTz+0.3*Count*Tavg#(Eq. W-1B)
Where:
Ei	=	Annual total volumetric emissions of GHGi from natural gas intermittent bleed pneumatic devices in standard cubic feet.
GHGi	=	Concentration of GHGi, CH4, or CO2, in natural gas supplied to the intermittent bleed device as defined in paragraph (u)(2) of this section.
x	=	Total number of intermittent bleed devices detected as malfunctioning in any pneumatic device monitoring survey during the year. A component found as malfunctioning in two or more surveys during the year is counted as one malfunctioning component.
24.1	=	Whole gas emission factor for malfunctioning intermittent bleed natural gas pneumatic devices, in standard cubic feet per hour per device.
Tz	=	The total time the surveyed pneumatic device "z" was in service (i.e., supplied with natural gas) and assumed to be leaking, in hours. If one pneumatic device monitoring survey is conducted in the calendar year, assume the device found malfunctioning was malfunctioning for the entire calendar year. If multiple pneumatic device monitoring surveys are conducted in the calendar year, assume a device found malfunctioning in the first survey was malfunctioning since the beginning of the year until the date of the survey; assume a device found malfunctioning in the last survey of the year was malfunctioning from the preceding survey through the end of the year; assume a device found malfunctioning in a survey between the first and last surveys of the year was malfunctioning since the preceding survey until the date of the survey; and sum times for all malfunctioning periods.
0.3	=	Whole gas emission factor for properly operating intermittent bleed natural gas pneumatic devices, in standard cubic feet per hour.
Count	=	Total number of intermittent bleed devices that were never observed to be malfunctioning during any monitoring survey during the year.
Tavg	=	The average time the pneumatic devices that were never observed to be malfunctioning during any monitoring survey were in service (i.e., supplied with natural gas) using engineering estimates based on best available data. Default is 8,760 hours.
(i) You must conduct pneumatic device monitoring surveys using the methods in either paragraph (a)(6)(i) or (ii) of this paragraph.
(A) For intermittent bleed natural gas pneumatic devices that are subject to monitoring requirements in part 60, subpart OOOOb of this chapter or an approved state plan or Federal plan in part 62 of this chapter, as applicable, you must use the methods specified in the applicable standard.
(B) For intermittent bleed natural gas pneumatic devices that are not subject to monitoring requirements in part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter and that you elect to monitor, you must use the methods specified in part 60, subpart OOOOb of this chapter.
(ii) You must conduct at least one complete pneumatic device monitoring survey in a calendar year. If you conduct multiple complete pneumatic device monitoring surveys in a calendar year, you must use the results from each complete pneumatic device monitoring survey when calculating emissions using Equation W-1B.
(iii) Calculate both CO2 and CH4 mass emissions using calculations in paragraph (v) of this section.
*	*	*	*	*
(c) Natural gas driven pneumatic pump venting. Calculate emissions from natural gas driven pneumatic pumps venting directly to the atmosphere as specified in paragraphs (c)(1) and (2) of this section. Calculate emissions from natural gas driven pneumatic pumps routed to flares, combustion, or vapor recovery systems as specified in paragraph (c)(3) of this section. You do not have to calculate emissions from natural gas driven pneumatic pumps covered in paragraph (e) of this section under this paragraph (c).
(1) Calculate CH4 and CO2 volumetric emissions from natural gas driven pneumatic pump venting using Equation W-2 of this section.
		(Eq. W-2)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions in standard cubic feet per year from all natural gas driven pneumatic pump venting, for GHGi.
Count	=	Total number of natural gas driven pneumatic pumps that vented directly to the atmosphere.
EF	=	Population emission factors for natural gas driven pneumatic pumps (in standard cubic feet per hour per pump) listed in Table W-1A of this subpart for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities.
GHGi	=	Concentration of GHGi, CH4, or CO2, in produced natural gas as defined in paragraph (u)(2)(i) of this section.
T	=	Average estimated number of hours in the operating year the pumps that vented directly to the atmosphere were in service (i.e., supplied with natural gas) using engineering estimates based on best available data. Default is 8,760 hours for pumps that only vented directly to the atmosphere.
(2) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
(3) Calculate emissions from natural gas driven pneumatic pumps routed to flares, combustion, or vapor recovery systems as specified in paragraphs (c)(3)(i) or (ii) of this section, as applicable. If a pump was vented directly to the atmosphere for part of the year and routed to a flare, combustion, or vapor recovery system during another part of the year, then calculate emissions from the time the pump vents directly to the atmosphere as specified in paragraphs (c)(1) and (2) of this section and calculate emissions from the time the pump was routed to a flare or combustion as specified in paragraphs (c)(3)(i) and (ii) of this section, as applicable. For emissions that are collected in a vapor recovery system that is not routed to combustion, paragraphs (c)(1), (2), (3)(i), and (3)(ii) do not apply and no emissions calculations are required.
(i) If any natural gas driven pneumatic pumps were routed to a flare, you must calculate CH4, CO2, and N2O emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attributable to natural gas driven pneumatic pumps from the flare.
(ii) If emissions from any natural gas driven pneumatic pumps were routed to combustion, you must calculate emissions for the combustion equipment as specified in paragraph (z) of this section and report emissions from the combustion equipment as specified in § 98.236(z).
(d) Acid gas removal (AGR) vents. For AGR vents (including processes such as amine, membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for CO2 only (not CH4) vented directly to the atmosphere or emitted through an 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 methods described in paragraphs (d)(1) through (4) of this section, and also comply with paragraphs (d)(5) through (11), as applicable. For AGR emissions that are routed to a flare, calculate the flared emissions as specified in paragraph (d)(12) of this section.
*	*	*	*	*
(4) *	*	*
(vi) Solvent type, pressure, temperature, circulation rate, and composition.
*	*	*	*	*
(12) For AGR vents routed to a flare, calculate CO2 emissions from the AGR as specified in paragraph (d)(12)(i) or (ii) of this section, as applicable.
(i) For emissions from an AGR unit that are routed to a dedicated flare, or if the emissions from the AGR unit are comingled with emissions from any other source types for routing to a flare and you do not continuously measure either flow or composition of the comingled gas stream, then calculate CO2 emissions from the AGR using a method specified in paragraph (d)(1) through (4) of this section, as applicable. You must also incorporate your AGR data into the parameters Vs and XCO2 in Equation W-20 to account for the AGR portion of the total flared CO2 emissions for all miscellaneous flared sources as described in paragraphs (n)(1) and (2) of this section.
(ii) For emissions from an AGR unit that are comingled with emissions from any other source types for routing to a flare and you continuously measure flow and/or composition of the comingled gas stream, then calculate total emissions from all miscellaneous flared sources (which includes AGRs) for the flare(s) to which the AGR emissions are routed using the procedures specified in paragraphs (n)(1) through (8) of this section. Use site-specific engineering estimates based on best available data to calculate the portion of the total flared CO2 emissions from the miscellaneous flared sources that entered the flare from the AGR. Report the calculated portion of the total flared CO2 emissions that entered the flare from the AGR as CO2 emissions from the AGR as specified in § 98.236(d)(1)(v). Subtract this amount of CO2 from the total flared CO2 and report the remainder as CO2 from miscellaneous flared sources as specified in § 98.236(n)(1)(xi).
(e) Dehydrator vents. For dehydrator vents, calculate annual CH4 and CO2 emissions using the applicable calculation methods described in paragraphs (e)(1) through (5) of this section. If emissions from dehydrator vents are routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (e)(4) of this section. If emissions from dehydrator vents are routed to a flare or regenerator firebox/fire tubes, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (e)(5) of this section.
(1) Calculation Method 1. Calculate annual mass emissions from glycol dehydrators that have an annual average of daily natural gas throughput that is greater than or equal to 0.4 million standard cubic feet per day by using a software program, such as AspenTech HYSYS(R) or GRI-GLYCalcTM, that uses the Peng-Robinson equation of state to calculate the equilibrium coefficient, speciates CH4 and CO2 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. Emissions must be modeled from both the still vent and, if applicable, the flash tank vent. The following parameters must be determined by engineering estimate based on best available data and must be used at a minimum to characterize emissions from dehydrators:
*	*	*	*	*
(x) Wet natural gas temperature and pressure at the absorber inlet.
*	*	*	*	*
(2) Calculation Method 2. Calculate annual volumetric emissions from glycol dehydrators that have an annual average of daily natural gas throughput that is less than 0.4 million standard cubic feet per day using Equation W-5 of this section, and then calculate the collective CH4 and CO2 mass emissions from the volumetric emissions using the procedures in paragraph (v) of this section:
*	*	*	*	*
Count	=	Total number of glycol dehydrators that have an annual average daily natural gas throughput that is greater than 0 million standard cubic feet per day and less than 0.4 million standard cubic feet per day.
*	*	*	*	*
(4) If the dehydrator unit has vapor recovery, calculate annual emissions as specified in paragraphs (e)(4)(i) and (ii) of this section.
(i) Adjust the emissions estimated in paragraphs (e)(1) and (2) of this section, as applicable, downward by the magnitude of emissions recovered using a vapor recovery system and by the amount of emissions routed to flares or regenerator firebox/fire tubes as determined by engineering estimate based on best available data. Report unrecovered emissions that are not routed to flares or regenerator fireboxes/fire tubes as emissions vented directly to the atmosphere.
(ii) If unrecovered emissions from the dehydrator are routed to flares or regenerator fireboxes/fire tubes, use the calculation method of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas vent. Use the volume routed to the flares or regenerator fireboxes/fire tubes and the dehydrator vent gas composition as determined using either engineering estimates based on best available data or the procedures specified in paragraph (u)(2) of this section, as applicable. Report unrecovered emissions that are routed to flares or regenerator fireboxes/fire tubes as flared emissions from dehydrators.
(5) If any dehydrator vent streams are routed to a flare or regenerator firebox/fire tubes, calculate emissions from these devices attributable to dehydrators as specified in paragraphs (e)(5)(i) through (v) of this section. If you operate a CEMS to monitor the emissions from the flare in accordance with paragraph (n)(8) of this section, calculate emissions as specified in paragraph (e)(5)(v) of this section instead of the provisions of paragraphs (e)(5)(i) through (iv) of this section.
(i) Determine the volume of gas from the dehydrator(s) to each flare using any of the methods specified in paragraphs (e)(5)(i)(A) or (B) of this section. You are not required to use the same method for all dehydrator streams.
(A) Use the vented volume as determined in paragraphs (e)(1) through (4) of this section.
(B) Measure the flow from the dehydrator(s) to the flare or regenerator firebox/fire tubes using a continuous flow measurement device. If the measured volume is in a manifold that combines flow from multiple dehydrators or from dehydrators and other sources, use engineering calculations based on process knowledge and best available data to estimate the portion(s) of the total flow (in scf) from each large dehydrator or from all small dehydrators combined.
(ii) Except as specified in paragraph (e)(5)(iii) of this section, determine composition of the gas from the dehydrator(s) to each flare or regenerator firebox/fire tubes using any of the methods specified in paragraphs (e)(5)(ii)(A) through (C) of this section. You are not required to use the same method for all dehydrator streams.
(A) Use the gas composition as determined in paragraphs (e)(1) through (4) of this section.
(B) Measure the composition of the gas from the dehydrator(s) to the flare or regenerator firebox/fire tubes using a continuous composition analyzer. If the measured composition is in a manifold that combines streams only from multiple dehydrators, assume the measured composition applies to all dehydrators that route gas through the manifold.
(C) Measure the composition of the total gas to the flare or regenerator firebox/fire tubes using a continuous composition analyzer. If the measured composition is in a manifold that combines flow from dehydrators and other sources, use engineering calculations based on available sampling data for other sources, process knowledge, and best available data to estimate the composition of the flow from each large dehydrator or from all small dehydrators combined.
(iii) If you continuously measure flow and/or gas composition in accordance with paragraphs (e)(5)(i)(B), (ii)(B), or (ii)(C) of this section, then those measured data must be used, either directly or after disaggregating to individual sources, to calculate dehydrator emissions from flares or regenerator firebox/fire tubes.
(iv) Use the calculation method of flare stacks in paragraphs (n)(3) through (7) of this section to calculate annual dehydrator emissions from flares or regenerator firebox/fire tubes.
(v) If you monitor the flare with CEMS, use the calculation procedures in paragraph (n)(8) of this section. If the flare receives gas from multiple dehydrators or from both dehydrators and other sources, then use engineering calculations based on process knowledge and best available data to estimate the portions of the total CO2 emissions measured by the CEMS that are from each large dehydrator and from all small dehydrators combined.
*	*	*	*	*
(g) *	*	*
(4) If any streams from well completions and workovers with hydraulic fracturing are flared, calculate annual emissions as specified in paragraphs (g)(4)(i) through (v) of this section. If you operate a CEMS to monitor the emissions from the flare in accordance with paragraph (n)(8) of this section, calculate emissions as specified in paragraph (g)(4)(v) of this section instead of the provisions of paragraphs (g)(4)(i) through (iv) of this section.
(i) Determine the volume of gas from well completions and workovers with hydraulic fracturing routed to each flare using any of the methods specified in paragraphs (g)(4)(i)(A) or (B) of this section. You are not required to use the same method for all streams.
(A) Use the volume from gas venting to the atmosphere during well completions and workovers with hydraulic fracturing as determined in paragraph (g) of this section. Subtract the estimated amount vented to the atmosphere, if any, from this total volume.
(B) Measure the flow from well completions and workovers with hydraulic fracturing to the flare using a continuous flow measurement device. If the measured volume is in a manifold that combines flow from well completions and workovers with hydraulic fracturing and other sources, use engineering calculations based on process knowledge and best available data to estimate the portion(s) of the total flow (in scf) from well completions and workovers with hydraulic fracturing.
(ii) Except as specified in paragraph (g)(4)(iii) of this section, determine composition of the gas from well completions and workovers with hydraulic fracturing to each flare using any of the methods specified in paragraphs (g)(4)(ii)(A) through (C) of this section. You are not required to use the same method for all streams.
(A) Use the gas composition as determined in paragraph (g)(3) of this section.
(B) Measure the composition of the gas from well completions and workovers with hydraulic fracturing to the flare using a continuous composition analyzer. If the measured composition is in a manifold that combines streams only from well completions and workovers with hydraulic fracturing, assume the measured composition applies to all completions and workovers with hydraulic fracturing that route gas through the manifold.
(C) Measure the composition of the total gas to the flare using a continuous composition analyzer. If the measured composition is in a manifold that combines flow from well completions and workovers with hydraulic fracturing and other sources, use engineering calculations based on available sampling data for other sources, process knowledge, and best available data to estimate the composition of the flow from each well completions and workovers with hydraulic fracturing.
(iii) If you continuously measure flow and/or gas composition in accordance with paragraphs (g)(4)(i)(B), (ii)(B), or (ii)(C) of this section, then those measured data must be used, either directly or after disaggregating to individual sources, to calculate well completion and workover from hydraulic fracturing emissions from flares.
(iv) Use the calculation method of flare stacks in paragraphs (n)(3) through (7) of this section to calculate annual emissions for the portion of gas flared during well completions and workovers using hydraulic fracturing.
(v) If you monitor the flare with CEMS, use the calculation procedures in paragraph (n)(8) of this section. If the flare receives gas from multiple well completions and workovers with hydraulic fracturing or from both well completions and workovers with hydraulic fracturing and other sources, then use engineering calculations based on process knowledge and best available data to estimate the portions of the total CO2 emissions measured by the CEMS that are from well completions and workovers with hydraulic fracturing.
(h) *	*	*
(2) If any streams from gas well completions and workovers without hydraulic fracturing are flared, calculate annual emissions of CH4, CO2, and N2O as specified in paragraphs (h)(2)(i) through (v) of this section. If you operate a CEMS to monitor the emissions from the flare in accordance with paragraph (n)(8) of this section, calculate emissions as specified in paragraph (h)(2)(v) of this section instead of the provisions of paragraphs (h)(2)(i) through (iv) of this section.
(i) Determine the volume of gas from well completions and workovers without hydraulic fracturing routed to each flare using any of the methods specified in paragraphs (h)(2)(i)(A) or (B) of this section. You are not required to use the same method for all streams.
(A) Use the gas well venting volume during well completions and workovers without hydraulic fracturing that are flared as determined using the methods specified in paragraphs (h) and (h)(1) of this section.
(B) Measure the flow from well completions and workovers without hydraulic fracturing to the flare using a continuous flow measurement device. If the measured volume is in a manifold that combines flow from well completions and workovers without hydraulic fracturing and other sources, use engineering calculations based on process knowledge and best available data to estimate the portion(s) of the total flow (in scf) from well completions and workovers without hydraulic fracturing.
(ii) Determine composition of the gas from well completions and workovers without hydraulic fracturing to each flare using any of the methods specified in paragraphs (h)(2)(ii)(A) through (C) of this section. You are not required to use the same method for all streams.
(A) Use the gas composition as determined in paragraphs (h) and (h)(1) of this section.
(B) Measure the composition of the gas from well completions and workovers without hydraulic fracturing to the flare using a continuous composition analyzer. If the measured composition is in a manifold that combines streams only from well completions and workovers without hydraulic fracturing, assume the measured composition applies to all completions and workovers without hydraulic fracturing that route gas through the manifold.
(C) Measure the composition of the total gas to the flare using a continuous composition analyzer. If the measured composition is in a manifold that combines flow from well completions and workovers without hydraulic fracturing and other sources, use engineering calculations based on available sampling data for other sources, process knowledge, and best available data to estimate the composition of the flow from each well completions and workovers without hydraulic fracturing.
(iii) If you continuously measure flow and/or gas composition in accordance with paragraphs (h)(2)(i)(B), (ii)(B), or (ii)(C) of this section, then those measured data must be used, either directly or after disaggregating to individual sources, to calculate well completion and workover from hydraulic fracturing emissions from flares.
(iv) Use the calculation method of flare stacks in paragraphs (n)(3) through (7) of this section to calculate annual emissions from the flare for gas well venting to a flare during completions and workovers without hydraulic fracturing.
(v) If you monitor the flare with CEMS, use the calculation procedures in paragraph (n)(8) of this section. If the flare receives gas from multiple well completions and workovers without hydraulic fracturing or from both well completions and workovers without hydraulic fracturing and other sources, then use engineering calculations based on process knowledge and best available data to estimate the portions of the total CO2 emissions measured by the CEMS that are from well completions and workovers without hydraulic fracturing.
(i) Blowdown vent stacks. Calculate CO2 and CH4 blowdown vent stack emissions from the depressurization of equipment to reduce system pressure for planned or emergency shutdowns resulting from human intervention or to take equipment out of service for maintenance as specified in either paragraph (i)(2) or (3) of this section. You may use the method in paragraph (i)(2) of this section for some blowdown vent stacks at your facility and the method in paragraph (i)(3) of this section for other blowdown vent stacks at your facility. Equipment with a unique physical volume of less than 50 cubic feet as determined in paragraph (i)(1) of this section are not subject to the requirements in paragraphs (i)(2) through (4) of this section. The requirements in this paragraph (i) do not apply to blowdown vent stack emissions from depressurizing to a flare, over-pressure relief, operating pressure control venting, and blowdown of non-GHG gases.
*	*	*	*	*
(2) Method for determining emissions from blowdown vent stacks according to equipment or event type. If you elect to determine emissions according to each equipment or event type, using unique physical volumes as calculated in paragraph (i)(1) of this section, you must calculate emissions as specified in paragraph (i)(2)(i) of this section and either paragraph (i)(2)(ii) of this section or, if applicable, paragraph (i)(2)(iii) of this section for each equipment or event type. Categorize equipment and event types for each industry segment as specified in paragraph (i)(2)(iv) of this section.
(i) *	*	*
*	*	* (Eq. W-14A)
*	*	*	*	*
Ta	=	Temperature at actual conditions in the unique physical volume (°F). For emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities and onshore natural gas transmission pipeline facilities, engineering estimates based on best available information may be used to determine the temperature.
*	*	*	*	*
Pa	=	Absolute pressure at actual conditions in the unique physical volume (psia). For emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities and onshore natural gas transmission pipeline facilities, engineering estimates based on best available information may be used to determine the pressure.
*	*	*	*	*
*	*	* (Eq. W-14B)
*	*	*	*	*
Ta,p	=	Temperature at actual conditions in the unique physical volume (°F) for each blowdown "p". For emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities and onshore natural gas transmission pipeline facilities, engineering estimates based on best available information may be used to determine the temperature.
*	*	*	*	*
Pa,b,p	=	Absolute pressure at actual conditions in the unique physical volume (psia) at the beginning of the blowdown "p". For emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities and onshore natural gas transmission pipeline facilities, engineering estimates based on best available information may be used to determine the pressure at the beginning of the blowdown.
Pa,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. For emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities and onshore natural gas transmission pipeline facilities, engineering estimates based on best available information may be used to determine the pressure at the end of the blowdown.
*	*	*	*	*
(iv) Categorize blowdown vent stack emission events as specified in paragraphs (i)(2)(iv)(A) and (B) of this section, as applicable.
(A) For the onshore natural gas processing, transmission compression, LNG import and export equipment, and onshore petroleum and natural gas gathering and boosting industry segments, equipment or event types must be grouped into the following seven categories: Facility piping (i.e., physical volumes associated with piping for which the entire physical volume is located within the facility boundary), pipeline venting (i.e., physical volumes associated with pipelines for which a portion of the physical volume is located outside the facility boundary and the remainder, including the blowdown vent stack, is located within the facility boundary), compressors, scrubbers/strainers, pig launchers and receivers, emergency shutdowns (this category includes emergency shutdown blowdown emissions regardless of equipment type), and all other equipment with a physical volume greater than or equal to 50 cubic feet. If a blowdown event resulted in emissions from multiple equipment types and the emissions cannot be apportioned to the different equipment types, then categorize the blowdown event as the equipment type that represented the largest portion of the emissions for the blowdown event.
(B) For the onshore natural gas transmission pipeline segment, pipeline segments or event types must be grouped into the following eight categories: Pipeline integrity work (e.g., the preparation work of modifying facilities, ongoing assessments, maintenance or mitigation), traditional operations or pipeline maintenance, equipment replacement or repair (e.g., valves), pipe abandonment, new construction or modification of pipelines including commissioning and change of service, operational precaution during activities (e.g. excavation near pipelines), emergency shutdowns including pipeline incidents as defined in 49 CFR 191.3, and all other pipeline segments with a physical volume greater than or equal to 50 cubic feet. If a blowdown event resulted in emissions from multiple categories and the emissions cannot be apportioned to the different categories, then categorize the blowdown event in the category that represented the largest portion of the emissions for the blowdown event.
*	*	*	*	*
(j) Onshore production and onshore petroleum and natural gas gathering and boosting storage tanks. Calculate CH4, CO2, and N2O (when flared) emissions from atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities (including stationary liquid storage not owned or operated by the reporter), as specified in this paragraph (j). For gas-liquid separators or onshore petroleum and natural gas gathering and boosting non-separator equipment (e.g., stabilizers, slug catchers) with annual average daily throughput of hydrocarbon liquids greater than or equal to 10 barrels per day, calculate annual CH4 and CO2 using Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (2) of this section. For wells flowing directly to atmospheric storage tanks without passing through a separator with throughput greater than or equal to 10 barrels per day, calculate annual CH4 and CO2 emissions using Calculation Method 2 as specified in paragraph (j)(2) of this section. For hydrocarbon liquids flowing to gas-liquid separators or non-separator equipment or directly to atmospheric storage tanks with throughput less than 10 barrels per day, use Calculation Method 3 as specified in paragraph (j)(3) of this section. If you use Calculation Method 1 or Calculation Method 2 for separators, you must also calculate emissions that may have occurred due to dump valves not closing properly using the method specified in paragraph (j)(6) of this section. If emissions from atmospheric pressure fixed roof storage tanks are routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (j)(4) of this section. If emissions from atmospheric pressure fixed roof storage tanks are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (j)(5) of this section.
(1) Calculation Method 1. Calculate annual CH4 and CO2 emissions from onshore production storage tanks and onshore petroleum and natural gas gathering and boosting storage tanks using operating conditions in the last gas-liquid separator or non-separator equipment before liquid transfer to storage tanks. Calculate flashing emissions with a software program, such as AspenTech HYSYS(R) or API 4697 E&P Tank, that uses the Peng-Robinson equation of state, models flashing emissions, and speciates CH4 and CO2 emissions that will result when the hydrocarbon liquids from the separator or non-separator equipment enter an atmospheric pressure storage tank. The following parameters must be determined for typical operating conditions over the year by engineering estimate and process knowledge based on best available data, and must be used at a minimum to characterize emissions from liquid transferred to tanks:
*	*	*	*	*
(iii) Sales oil or stabilized hydrocarbon liquids API gravity.
(iv) Sales oil or stabilized hydrocarbon liquids production rate.
*	*	*	*	*
(vii) Separator or non-separator equipment hydrocarbon liquids composition and Reid vapor pressure. If this data is not available, determine these parameters by using one of the methods described in paragraphs (j)(1)(vii)(A) through (C) of this section.
(A) If separator or non-separator equipment hydrocarbon liquid composition and Reid vapor pressure default data are provided with the software program, select the default values that most closely match your separator or non-separator equipment pressure first, and API gravity secondarily.
(B) If separator or non-separator equipment hydrocarbon liquids composition and Reid vapor pressure data are available through your previous analysis, select the latest available analysis that is representative of produced crude oil or condensate from the sub-basin category for onshore petroleum and natural gas production or from the county for onshore petroleum and natural gas gathering and boosting.
(C) Analyze a representative sample of separator or non-separator equipment hydrocarbon liquids in each sub-basin category for onshore petroleum and natural gas production or each county for onshore petroleum and natural gas gathering and boosting for hydrocarbon liquids composition and Reid vapor pressure using an appropriate standard method published by a consensus-based standards organization.
(2) Calculation Method 2. Calculate annual CH4 and CO2 emissions using the methods in paragraph (j)(2)(i) of this section for gas-liquid separators with annual average daily throughput of hydrocarbon liquids greater than or equal to 10 barrels per day. Calculate annual CH4 and CO2 emissions using the methods in paragraph (j)(2)(ii) of this section for wells with annual average daily hydrocarbon liquids production greater than or equal to 10 barrels per day that flow directly to atmospheric storage tanks in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting (if applicable). Calculate annual CH4 and CO2 emissions using the methods in paragraph (j)(2)(iii) of this section for non-separator equipment with annual average daily hydrocarbon liquids throughput greater than or equal to 10 barrels per day that flow directly to atmospheric storage tanks in onshore petroleum and natural gas gathering and boosting.
(i) Flow to storage tank after passing through a separator. Assume that all of the CH4 and CO2 in solution at separator temperature and pressure is emitted from hydrocarbon liquids sent to storage tanks. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as described in § 98.234(b) to sample and analyze separator hydrocarbon liquids composition at separator pressure and temperature.
(ii) Flow to storage tank direct from wells. Calculate CH4 and CO2 emissions using either of the methods in paragraph (j)(2)(ii)(A) or (B) of this section.
(A) If well production hydrocarbon liquids and gas compositions are available through a previous analysis, select the latest available analysis that is representative of produced hydrocarbon liquids and gas from the sub-basin category and assume all of the CH4 and CO2 in both hydrocarbon liquids and gas are emitted from the tank.
(B) If well production hydrocarbon liquids and gas compositions are not available, use default hydrocarbon liquids and gas compositions in software programs, such as API 4697 E&P Tank, that most closely match the well production gas/oil ratio and API gravity and assume all of the CH4 and CO2 in both hydrocarbon liquids and gas are emitted from the tank.
(iii) Flow to storage tank direct from non-separator equipment. Calculate CH4 and CO2 emissions using either of the methods in paragraph (j)(2)(iii)(A) or (B) of this section.
(A) If other non-separator equipment hydrocarbon liquids and gas compositions are available through a previous analysis, select the latest available analysis that is representative of hydrocarbon liquids and gas from non-separator equipment in the same county and assume all of the CH4 and CO2 in both hydrocarbon liquids and gas are emitted from the tank.
(B) If non-separator equipment hydrocarbon liquids and gas compositions are not available, use default hydrocarbon liquids and gas compositions in software programs, such as API 4697 E&P Tank, that most closely match the non-separator equipment gas/liquid ratio and API gravity and assume all of the CH4 and CO2 in both hydrocarbon liquids and gas are emitted from the tank.
(3) *	*	*
*	*	*	*	*
Count	=	Total number of separators, wells, or non-separator equipment with annual average daily throughput less than 10 barrels per day. Count only separators, wells, or non-separator equipment that feed hydrocarbon liquids directly to the storage tank.
*	*	*	*	*
(4) If the storage tank receiving your hydrocarbon liquids has a vapor recovery system, calculate annual emissions from storage tanks as specified in paragraphs (j)(4)(i) and (ii) of this section.
(i) Using engineering estimates based on best available data, determine the portion of the total emissions estimated in paragraphs (j)(1) through (3) of this section that is recovered using a vapor recovery system. You must take into account periods with reduced capture efficiency of the vapor recovery system (e.g., when a thief hatch is open or not properly seated) when calculating emissions recovered.
(ii) Determine total emissions not recovered by a vapor recovery system as specified in paragraphs (j)(4)(ii)(A) and (B) of this section.
(A) Adjust the emissions estimated in paragraphs (j)(1) through (3) of this section downward by the magnitude of emissions recovered using a vapor recovery system and by the amount of emissions routed to flares. Unrecovered emissions may include, but are not limited to, emissions during periods when the vapor recovery system is not operating, losses from the tank when the vapor recovery system is not operating and the tank is connected to a flare, and losses from the tank during periods when the vapor recovery system is operating. These losses may include, but are not limited to, emissions due to open or unseated thief hatches. Report unrecovered emissions that are not routed to flares as emissions vented directly to the atmosphere.
(B) If unrecovered emissions from atmospheric tanks are routed to flares, determine the volume of gas routed to flares, calculate annual emissions from flares as specified in paragraphs (j)(5)(i) through (iii) of this section, and report as flared emissions from atmospheric tanks.
(5) If the storage tank receiving your hydrocarbon liquids has a flare(s), calculate annual flared emissions from storage tanks as specified in paragraphs (j)(5)(i) through (v) of this section and calculate emissions vented directly to the atmosphere as specified in paragraph (j)(5)(vi) of this section. For atmospheric tanks with emissions calculated using Calculation Method 3 in paragraph (j)(3) of this section, this paragraph (j)(5) only applies when at least half of the hydrocarbon liquids flowing to gas-liquid separators or non-separator equipment or directly to atmospheric storage tanks are directed to atmospheric tanks that used flares to control emissions. If you operate a CEMS to monitor the emissions from the flare in accordance with paragraph (n)(8) of this section, calculate emissions as specified in paragraph (j)(5)(v) of this section instead of the provisions of paragraphs (j)(5)(i) through (iv) of this section.
(i) Estimate the volume routed to the flare using any of the methods specified in paragraphs (j)(5)(i)(A) or (B) of this section. You are not required to use the same method for all storage tanks.
(A) If unrecovered emissions from the storage tank are calculated in accordance with paragraph (j)(4) of this section, then determine the volume of the unrecovered emissions routed to flares based on best available data. If no emissions from the storage tank are routed to vapor recovery, then use the storage tank emissions volume as determined in paragraphs (j)(1) through (3) of this section, except that you must also adjust this total volume of emissions downward by the estimated portion of the total volume that is not routed to the flare (e.g., when the flare is bypassed or when a thief hatch is open or not properly seated). Estimate the volume of the emissions not routed to flares based on best available data.
(B) Measure the flow from the storage tank(s) to the flare using a continuous flow measurement device. If the measured volume is in a manifold that combines flow from storage tanks and other sources, use engineering calculations based on process knowledge and best available data to estimate the portion(s) of the total flow (in scf) from each storage tank.
(ii) Except as specified in paragraph (j)(5)(iii) of this section, determine the composition of the gas from the storage tanks routed to the flare using any of the methods specified in paragraphs (j)(5)(ii)(A) through (C) of this section. You are not required to use the same method for all storage tanks.
(A) If you use Calculation Method 1 or Calculation Method 2, use your gas composition as determined in paragraphs (j)(1) and (2) of this section. If you use Calculation Method 3 in paragraph (j)(3) of this section, determine the gas composition using either engineering estimates based on best available data or the procedures specified in paragraph (u)(2)(i) of this section.
(B) Measure the composition of the gas from the storage tanks to the flare using a continuous gas composition analyzer. If the measured composition is in a manifold that combines streams only from multiple storage tanks, assume the measured composition applies to all storage tanks that route gas through the manifold.
(C) Measure the composition of the total gas to the flare using a continuous composition analyzer. If the measured composition is in a manifold that combines flow from storage tanks and other sources, use engineering calculations based on available sampling data for other sources, process knowledge, and best available data to estimate the composition of the flow from storage tanks.
(iii) If you continuously measure flow and/or gas composition in accordance with paragraphs (j)(5)(i)(B), (ii)(B), or (ii)(C) of this section, then those measured data must be used, either directly or after disaggregating to individual sources, to calculate storage tank emissions from flares.
(iv) Use the calculation method of flare stacks in paragraphs (n)(3) through (7) of this section with the volume and composition determined according to paragraphs (j)(5)(i) and (ii) of this section to determine storage tank emissions from the flare.
(v) If you monitor the flare with CEMS, use the calculation procedures in paragraph (n)(8) of this section. If the flare receives gas from both storage tanks and other sources, then use engineering calculations based on process knowledge and best available data to estimate the portions of the total CO2 emissions measured by the CEMS that are from storage tanks.
(vi) For storage tanks with no vapor recovery system, if the volume routed to the flare as determined in paragraph (j)(5)(i)(A) or (B) of this section is less than the total volume of emissions from the tank as estimated in paragraphs (j)(1) through (3) of this section, then use the volume not sent to the flare to calculate emissions of flash gas vented directly to the atmosphere from the storage tank.
(6) If you use Calculation Method 1 or Calculation Method 2 in paragraph (j)(1) or (2) of this section, calculate emissions from occurrences of gas-liquid separator liquid dump valves not closing during the calendar year by using Equation W-16 of this section.
Es,i,dv=CFdvxEs,i8,760xTdv#(Eq. W-16)
Where:
Es,i,dv	=	Annual volumetric GHG emissions (either CO2 or CH4) at standard conditions in cubic feet from storage tanks that resulted from the dump valve on the gas-liquid separator not closing properly.
Es,i	=	Annual volumetric GHG emissions (either CO2 or CH4) as determined in paragraphs (j)(1), (j)(2) and, if applicable, (j)(4) and (5) of this section, in standard cubic feet per year, from storage tanks with dump valves on an associated gas-liquid separator that did not close properly.
Tdv	=	Total time a dump valve is not closing properly in the calendar year in hours. Estimate Tdv based on maintenance, operations, or routine separator inspections that indicate the period of time when the valve was malfunctioning in open or partially open position.
CFdv	=	Correction factor for tank emissions for time period Tdv is 2.87 for crude oil production. Correction factor for tank emissions for time period Tdv is 4.37 for gas condensate production.
8,760	=	Conversion to hourly emissions.
*	*	*	*	*
(k) *	*	*
(5) If any transmission storage tanks are routed to flares, calculate emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attributable to transmission tanks from the flare. If the volume to the flare is not continuously measured for the duration of time that flaring occurred, then conduct an annual leak measurement as specified in paragraph (k)(1)(ii) or (iv) of this section. If a leak is detected, quantify the leak in accordance with paragraph (k)(2)(i) or (ii) of this section and determine the time leaking as specified in paragraph (k)(3) of this section. Use these data when estimating total flow to the flare in accordance with paragraph (n)(1) of this section.
(l) *	*	*
(6) If any emissions from well testing are routed to a flare, calculate flared emissions from well testing as specified in paragraphs (l)(6)(i) through (v) of this section. If you operate a CEMS to monitor the emissions from the flare in accordance with paragraph (n)(8) of this section, calculate emissions as specified in paragraph (l)(6)(v) of this section instead of the provisions of paragraphs (l)(6)(i) through (iv) of this section.
(i) Determine the volume of gas from well testing to each flare using any of the methods specified in paragraphs (l)(6)(i)(A) or (B) of this section. You are not required to use the same method for all well testing.
(A) Use the well testing emissions volume as determined in paragraphs (l)(1) through (4) of this section.
(B) Measure the flow from well testing to the flare using a continuous flow measurement device. If the measured volume is in a manifold that combines flow from well testing and other sources, use engineering calculations based on process knowledge and best available data to estimate the portion(s) of the total flow (in scf) from well testing.
(ii) Except as specified in paragraph (l)(6)(iii) of this section, determine composition of the gas from well testing to each flare using any of the methods specified in paragraphs (l)(6)(ii)(A) through (C) of this section. You are not required to use the same method for all well testing.
(A) Use the gas composition as determined in paragraphs (l)(1) through (4) of this section.
(B) Measure the composition of gas from well testing to the flare using a continuous composition analyzer. If the measured composition is in a manifold that combines streams only from testing of multiple wells, assume the measured composition applies to all well testing gas routed through the manifold.
(C) Measure the composition of the total gas to the flare using a continuous composition analyzer. If the measured composition is in a manifold that combines flow from well testing and other sources, use engineering calculations based on available sampling data for other sources, process knowledge, and best available data to estimate the composition of the flow from well testing.
(iii) If you continuously measure flow and/or gas composition in accordance with paragraphs (l)(6)(i)(B), (ii)(B), or (ii)(C) of this section, then those measured data must be used, either directly or after disaggregating to individual sources, to calculate well testing emissions from flares.
(iv) Use the calculation method of flare stacks in paragraphs (n)(3) through (7) of this section to determine annual well testing emissions from the flare.
(v) If you monitor the flare with CEMS, use the calculation procedures in paragraph (n)(8) of this section. If the flare receives gas from both well testing and other sources, then use engineering calculations based on process knowledge and best available data to estimate the portions of the total CO2 emissions measured by the CEMS that are from well testing.
(m) *	*	*
(3) Estimate venting emissions using Equation W-18 of this section. Alternatively, if you measure the flow to a vent using a continuous flow measurement device, you must use the measured flow volumes to calculate vented associated gas emissions.
*	*	*	*	*
Vp,q	=	Volume of oil produced, for well p in sub-basin q, in barrels in the calendar year only during time periods in which associated gas was vented or flared.
SGp,q	=	Volume of associated gas sent to sales, for well p in sub-basin q, in standard cubic feet of gas in the calendar year only during time periods in which associated gas was vented or flared.
*	*	*	*	*
(5) Calculate flared associated natural gas emissions as specified in paragraphs (m)(5)(i) through (v) of this section. If you operate a CEMS to monitor the emissions from the flare in accordance with paragraph (n)(8) of this section, calculate emissions as specified in paragraph (m)(5)(v) of this section instead of the provisions of paragraphs (m)(5)(i) through (iv) of this section.
(i) Determine the volume of associated gas to each flare using any of the methods specified in paragraphs (m)(5)(i)(A) or (B) of this section. You are not required to use the same method for all associated gas streams.
(A) Use the associated natural gas volume as determined in paragraphs (m)(1) through (4) of this section.
(B) Measure the flow of associated gas to the flare using a continuous flow measurement device. If the measured volume is in a manifold that combines flow from multiple associated gas streams or from associated gas streams and other sources, use engineering calculations based on process knowledge and best available data to estimate the portions of the total flow (in scf) that is associated gas.
(ii) Except as specified in paragraph (m)(5)(iii) of this section, determine composition of the associated gas to each flare using any of the methods specified in paragraphs (m)(5)(ii)(A) through (C) of this section. You are not required to use the same method for all associated gas streams.
(A) Use the associated gas composition as determined in paragraphs (m)(1) through (4) of this section.
(B) Measure the composition of the associated gas to the flare using a continuous composition analyzer. If the measured composition is in a manifold that combines only associated gas streams, assume the measured composition applies to all associated gas that is routed through the manifold.
(C) Measure the composition of the total gas to the flare using a continuous composition analyzer. If the measured composition is in a manifold that combines both associated gas and gas from other sources, use engineering calculations based on available sampling data for other sources, process knowledge, and best available data to estimate the composition of the associated gas in the combined stream.
(iii) If you continuously measure flow and/or gas composition in accordance with paragraphs (m)(5)(i)(B), (ii)(B), or (ii)(C) of this section, then those measured data must be used, either directly or after disaggregating to individual sources, to calculate associated gas emissions from flares.
(iv) Use the calculation method of flare stacks in paragraphs (n)(3) through (7) of this section to calculate annual associated gas emissions from flares.
(v) If you monitor the flare with CEMS, use the calculation procedures in paragraph (n)(8) of this section. If the flare receives both associated gas and gas from other sources, then use engineering calculations based on process knowledge and best available data to estimate the portions of the total CO2 emissions measured by the CEMS that are from associated gas.
(n) Flare stack emissions. As applicable for the industry segment, use the procedures in paragraphs (n)(3) through (9) of this section to calculate CO2, CH4, and N2O emissions per flare stack separately from dehydrators as specified in paragraph (e)(5) of this section, completions and workovers with hydraulic fracturing as specified in paragraph (g)(4) of this section, completions and workovers without hydraulic fracturing as specified in paragraph (h)(2) of this section, atmospheric tanks as specified in paragraph (j)(5) of this section, well testing as specified in paragraph (l)(6) of this section, and associated gas as specified in paragraph (m)(5) of this section. Also use the procedures specified in paragraphs (n)(1) through (9) of this section to calculate the collective emissions per flare stack from all miscellaneous flared sources (i.e., sources that are not subject to source-specific flared emissions reporting for your industry segment).
(1) If you have a continuous flow measurement device on gas to the flare, you must use the measured flow volumes to calculate the flare gas emissions from miscellaneous flared sources. 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. If you do not have a continuous flow measurement device on gas to the flare, or if a continuous flow measurement device measures a stream that combines flow from sources that are subject to source-specific flared emissions reporting as well as flow from miscellaneous flared sources, you can use engineering calculations based on process knowledge and best available data to estimate the flow from the miscellaneous flared sources. Best available data also includes the procedures specified in paragraphs (e)(5), (g)(4), (h)(2), (j)(5), (k)(5), (l)(6), and (m)(5) of this section. If a continuous flow measurement device is not installed on an AGR that is routed to a flare, the volumetric CO2 emissions calculated using AGR Calculation Method 3 or 4 and paragraph (d)(9) of this section must be incorporated into the parameter Vs in Equation W-20 to account for the AGR portion of the total flared CO2 emissions.
(2) If you have a continuous gas composition analyzer on gas to the flare, you must use these compositions in calculating emissions from miscellaneous flared sources, except when the measured stream to the flare includes emissions from an AGR unit that are comingled with emissions from other sources. If you do not have a continuous gas composition analyzer on gas to the flare, or if the stream to the flare consists of AGR emissions that are comingled with emissions from other sources, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare from an emission source other than an AGR vent as specified in paragraphs (n)(2)(i) through (iii) of this section. For emissions from AGR vents that do not have a continuous gas composition analyzer, you may use either site-specific engineering estimates based on best available data or a default CO2 mole fraction of 1.
*	*	*	*	*
(5) Calculate GHG volumetric emissions from flaring at standard conditions using Equations W-19 and W-20 of this section. Emissions may be calculated per stream routed to the flare and then summed over all streams per emissions source type. Alternatively, you may sum the total volume of all streams from a particular emission source type, determine the flow-weighted average CO2 and hydrocarbon concentrations over all streams per source type, and then perform a single calculation using Equation W-19 and a single calculation using Equation W-20 to calculate the total CH4 and CO2 emissions per source type.
		(Eq. W-19)
		(Eq. W-20)
Where:
Es,CH4	=	Annual CH4 emissions per emission source type from flare stack in cubic feet, at standard conditions.
Es,CO2	=	Annual CO2 emissions per emission source type from flare stack in cubic feet, at standard conditions.
Vs	=	Volume of gas sent to flare per emission source type in standard cubic feet, during the year as determined in paragraph (e)(5)(i), (g)(4)(i), (h)(2)(i), (j)(5)(i), (l)(6)(i), (m)(5)(i), or (n)(1) of this section.
η	=	Flare combustion efficiency, expressed as fraction of gas combusted by a burning flare (default is 0.98).
XCH4	=	Mole fraction of CH4 in the feed gas to the flare per emission source type as determined in paragraph (e)(5)(ii), (g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii), (m)(5)(ii), or (n)(2) of this section. Use a flow-weighted mole fraction if multiple streams from the same source type are combined for the emissions calculation.
XCO2	=	Mole fraction of CO2 in the feed gas to the flare per emission source type as determined in paragraph (e)(5)(ii), (g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii), (m)(5)(ii), or (n)(2) of this section. Use a flow-weighted mole fraction if multiple streams from the same source type are combined for the emissions calculation.
ZU	=	Fraction of the feed gas sent to an un-lit flare per emission source type determined by engineering estimate and process knowledge based on best available data and operating records.
ZL	=	Fraction of the feed gas sent to a burning flare per emission source type (equal to 1 − ZU).
Yj	=	Mole fraction of hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes-plus) in the feed gas to the flare per emissions source type as determined in paragraph (e)(5)(ii), (g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii), (m)(5)(ii), or (n)(2) of this section.
Rj	=	Number of carbon atoms in the hydrocarbon constituent j in the feed gas to the flare per emission source type: 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes-plus).
*	*	*	*	*
(o) Centrifugal compressor venting. If you are required to report emissions from centrifugal compressor venting as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (5) of this section; perform calculations specified in paragraphs (o)(6) through (9) of this section; and calculate CH4 and CO2 mass emissions as specified in paragraph (o)(11) of this section. If you are required to report emissions from centrifugal compressor venting at an onshore petroleum and natural gas production facility as specified in § 98.232(c)(19) or an onshore petroleum and natural gas gathering and boosting facility as specified in § 98.232(j)(8), you must calculate volumetric emissions as specified in paragraph (o)(10); and calculate CH4 and CO2 mass emissions as specified in paragraph (o)(11). If emissions from a compressor source are routed to a flare, paragraphs (o)(1) through (11) do not apply and instead you must calculate CH4, CO2, and N2O emissions as specified in paragraph (o)(12) of this section. If emissions from a compressor source are routed to combustion, paragraphs (o)(1) through (12) do not apply and instead you must calculate and report emissions as specified in subpart C of this part or paragraph (z) of this section, as applicable. If emissions from a compressor source are routed to vapor recovery, paragraphs (o)(1) through (12) do not apply.
(1) *	*	*
(i) Centrifugal compressor source as found measurements. Measure venting from each compressor according to either paragraph (o)(1)(i)(A), (B), or (C) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraph (o)(1)(i)(D) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable monitoring and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this section.
(A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (o)(2)(i) of this section, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section if the compressor has wet seal oil degassing vents, and measure volumetric emissions from dry seal vents as specified in paragraph (o)(2)(iii) of this section if the compressor has dry seals.
(B) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in paragraph (o)(2)(i) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode.
(C) For a compressor measured in standby-pressurized-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (o)(2)(i) of this section, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section if the compressor has wet seal oil degassing vents, and measure volumetric emissions from dry seal vents as specified in paragraph (o)(2)(iii) of this section if the compressor has dry seals.
*	*	*	*	*
(2) Methods for performing as found measurements from individual centrifugal compressor sources. If conducting measurements for each compressor source, you must determine the volumetric emissions from blowdown valves and isolation valves as specified in paragraph (o)(2)(i) of this section, the volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section, and the volumetric emissions from dry seal vents as specified in paragraph (o)(2)(iii) of this section.
(i) For blowdown valves on compressors in operating-mode or in standby-pressurized-mode and for isolation valves on compressors in not-operating-depressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (o)(2)(i)(A) through (D) of this section.
*	*	*	*	*
(ii) For wet seal oil degassing vents in operating-mode or in standby-pressurized-mode, determine volumetric flow at standard conditions, using one of the methods specified in paragraphs (o)(2)(ii)(A) through (C) of this section. You must quantitatively measure the volumetric flow for wet seal oil degassing vent; you may not use screening methods set forth in § 98.234(a) to screen for emissions for the wet seal oil degassing vent.
(A) Use a temporary meter such as a vane anemometer or permanent flow meter according to methods set forth in § 98.234(b).
(B) Use calibrated bags according to methods set forth in § 98.234(c).
(C) Use a high volume sampler according to methods set forth in § 98.234(d).
(iii) For dry seal vents in operating-mode or in standby-pressurized-mode, determine volumetric flow at standard conditions from each dry seal vent using one of the methods specified in paragraphs (o)(2)(ii)(A) through (D) of this section. If a compressor has more than one dry seal vent, determine the aggregate dry seal vent volumetric flow for the compressor as the sum of the volumetric flows determined for each dry seal vent on the compressor.
(A) Use a temporary meter such as a vane anemometer or permanent flow meter according to methods set forth in § 98.234(b).
(B) Use calibrated bags according to methods set forth in § 98.234(c).
(C) Use a high volume sampler according to methods set forth in § 98.234(d).
(D) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these specified methods, then you must use one of the methods specified in paragraph (o)(2)(iii)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the methods. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening dry seal vents.
*	*	*	*	*
(4) *	*	*
(ii) *	*	*
(E) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these methods, then you must use one of the methods specified in paragraph (o)(4)(ii)(A) through (o)(4)(ii)(D) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening a manifolded group of compressor sources.
*	*	*	*	*
(6) *	*	*
(i) Using Equation W-21 of this section, calculate the annual volumetric GHG emissions for each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) through (C) of this section that was measured during the reporting year.
*	*	*	*	*
m	=	Compressor mode-source combination specified in paragraph (o)(1)(i)(A), (B), or (C) of this section that was measured for the reporting year.
(ii) Using Equation W-22 of this section, calculate the annual volumetric GHG emissions from each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) through (C) of this section that was not measured during the reporting year.
*	*	*	*	*
m	=	Compressor mode-source combination specified in paragraph (o)(1)(i)(A), (B), or (C) of this section that was not measured in the reporting year.
(iii) Using Equation W-23 of this section, develop an emission factor for each compressor mode-source combination specified in paragraphs (o)(1)(i)(A) through (C) of this section. These emission factors must be calculated annually and used in Equation W-22 of this section to determine volumetric emissions from a centrifugal compressor in the mode-source combinations that were not measured in the reporting year.
*	*	*	*	*
m	=	Compressor mode-source combination specified in paragraph (o)(1)(i)(A), (B), or (C) of this section.
*	*	*	*	*
(8) *	*	*
*	*	*	*	*
Tg	=	Total time the manifolded group of compressor sources g had potential for emissions in the reporting year, in hours. Include all time during which at least one compressor source in the manifolded group of compressor sources g was in a mode-source combination specified in either paragraph (o)(1)(i)(A), (o)(1)(i)(B), (o)(1)(i)(C), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. Default of 8760 hours may be used.
*	*	*	*	*
(10) Method for calculating volumetric GHG emissions from wet seal oil degassing vents at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility. You must calculate emissions from atmospheric centrifugal compressor wet seal oil degassing vents at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using Equation W-25 of this section. Emissions from centrifugal compressor wet seal oil degassing vents that are routed to a flare, combustion, or vapor recovery are not required to be determined under this paragraph (o).
*	*	*	*	*
Count	=	Total number of centrifugal compressors that have wet seal oil degassing vents that are vented to the atmosphere.
*	*	*	*	*
(p) Reciprocating compressor venting. If you are required to report emissions from reciprocating compressor venting as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (5) of this section; perform calculations specified in paragraphs (p)(6) through (9) of this section; and calculate CH4 and CO2 mass emissions as specified in paragraph (p)(11) of this section. If you are required to report emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility as specified in § 98.232(c)(11) or an onshore petroleum and natural gas gathering and boosting facility as specified in § 98.232(j)(5), you must calculate volumetric emissions as specified in paragraph (p)(10); and calculate CH4 and CO2 mass emissions as specified in paragraph (p)(11). If emissions from a compressor source are routed to a flare, paragraphs (p)(1) through (11) do not apply and instead you must calculate CH4, CO2, and N2O emissions as specified in paragraph (p)(12) of this section. If emissions from a compressor source are routed to combustion, paragraphs (p)(1) through (12) do not apply and instead you must calculate and report emissions as specified in subpart C of this part or paragraph (z) of this section, as applicable. If emissions from a compressor source are routed to vapor recovery, paragraphs (p)(1) through (12) do not apply.
(1) *	*	*
(i) Reciprocating compressor source as found measurements. Measure venting from each compressor according to either paragraph (p)(1)(i)(A), (B), or (C) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraph (p)(1)(i)(D) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable monitoring and QA/QC that is required by this paragraph (p) must be used in the calculations specified in this section.
(A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (p)(2)(i) of this section, and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section, as applicable.
(B) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in paragraph (p)(2)(i) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode.
(C) For a compressor measured in standby-pressurized-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (p)(2)(i) of this section and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section, as applicable.
(D) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for all existing compressors. For only the first year of operation of new compressors, calculate emissions according to paragraph (p)(6)(ii) of this section.
*	*	*	*	*
(2) Methods for performing as found measurements from individual reciprocating compressor sources. If conducting measurements for each compressor source, you must determine the volumetric emissions from blowdown valves and isolation valves as specified in paragraph (p)(2)(i) of this section. You must determine the volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section, as applicable.
*	*	*	*	*
(ii) For reciprocating rod packing equipped with an open-ended vent line on compressors in operating-mode or standby-pressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (p)(2)(ii)(A) through (C) of this section.
*	*	*	*	*
(C) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these specified methods, then you must use one of the methods specified in paragraph (p)(2)(ii)(A) and (B) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph (p)(2)(ii)(C), when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening or measuring rod packing emissions.
(iii) *	*	*
(A) You must use the methods described in § 98.234(a)(1) through (3) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or for compressors with a closed distance piece, conduct annual detection of gas emissions from the rod packing vent, distance piece vent, compressor crank case breather cap, or other vent emitting gas from the rod packing. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening rod packing emissions.
*	*	*	*	*
(4) *	*	*
(ii) *	*	*
(C) A high volume sampler according to methods set forth in § 98.234(d).
(D) [Reserved]
(E) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these specified methods, then you must use one of the methods specified in paragraph (p)(4)(ii)(A) through (D) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening a manifolded group of compressor sources.
*	*	*	*	*
(6) *	*	*
(ii) Using Equation W-27 of this section, calculate the annual volumetric GHG emissions from each reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of this section that was not measured during the reporting year.
*	*	*	*	*
(iii) Using Equation W-28 of this section, develop an emission factor for each compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of this section. These emission factors must be calculated annually and used in Equation W-27 of this section to determine volumetric emissions from a reciprocating compressor in the mode-source combinations that were not measured in the reporting year.
*	*	*	*	*
(10) Method for calculating volumetric GHG emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility. You must calculate emissions from reciprocating compressor atmospheric venting of rod packing emissions at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using Equation W-29D of this section. Reciprocating compressor rod packing emissions that are routed to a flare, combustion, or vapor recovery are not required to be determined under this paragraph (p).
*	*	*	*	*
Count	=	Total number of reciprocating compressors with rod packing emissions vented to the atmosphere.
*	*	*	*	*
(q) Equipment leak surveys. For the components identified in paragraphs (q)(1)(i) through (iii) of this section, you must conduct equipment leak surveys using the leak detection methods specified in paragraphs (q)(1)(i) through (iii) and (v) of this section. For the components identified in paragraph (q)(1)(iv) of this section, you may elect to conduct equipment leak surveys, and if you elect to conduct surveys, you must use a leak detection method specified in paragraph (q)(1)(iv) of this section. This paragraph (q) applies to components in streams with gas content greater than 10 percent CH4 plus CO2 by weight. Components in streams with gas content less than or equal to 10 percent CH4 plus CO2 by weight are exempt from the requirements of this paragraph (q) and do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of this paragraph (q) and do not need to be reported.
(1) Survey requirements. (i) For the components listed in § 98.232(e)(7), (f)(5), (g)(4), and (h)(5), that are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must conduct surveys using any of the leak detection methods listed in § 98.234(a) and calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section.
(ii) For the components listed in § 98.232(i)(1), you must conduct surveys using any of the leak detection methods listed in § 98.234(a) except § 98.234(a)(2)(ii) and calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section.
(iii) For the components listed in § 98.232(c)(21)(i), (e)(7), (e)(8), (f)(5), (f)(6), (f)(7), (f)(8), (g)(4), (g)(6), (g)(7), (h)(5), (h)(7), (h)(8), and (j)(10)(i) that are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must conduct surveys using any of the leak detection methods in § 98.234(a)(1)(ii), (iii), or (2)(ii), as applicable, and calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section.
(iv) For the components listed in § 98.232(c)(21)(i), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), or (j)(10)(i), that are not subject to fugitive emissions standards in § 60.5397a of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you may elect to conduct surveys according to this paragraph (q), and, if you elect to do so, then you must use one of the leak detection methods in § 98.234(a).
(A) If you elect to use a leak detection method in § 98.234(a) for the surveyed component types in § 98.232(c)(21)(i), (f)(7), (g)(6), (h)(7), or (j)(10)(i) in lieu of the population count methodology specified in paragraph (r) of this section, then you must calculate emissions for the surveyed component types in § 98.232(c)(21)(i), (f)(7), (g)(6), (h)(7), or (j)(10)(i) using the procedures in either paragraph (q)(2) or (3) of this section.
(B) If you elect to use a leak detection method in § 98.234(a) for the surveyed component types in § 98.232(e)(8), (f)(6), (f)(8), (g)(7), and (h)(8), then you must use the procedures in either paragraph (q)(2) or (3) of this section to calculate those emissions.
(C) If you elect to use a leak detection method in § 98.234(a)(1)(ii), (iii), or (2)(ii), as applicable, for any elective survey under this subparagraph (q)(1)(iv), then you must survey the component types in § 98.232(c)(21)(i), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), and (j)(10)(i) that are not subject to fugitive emissions standards in § 60.5397a of this chapter, [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, and you must calculate emissions from the surveyed component types in § 98.232(c)(21)(i), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), and (j)(10)(i) using the emission calculation requirements in either paragraph (q)(2) or (3) of this section.
(v) For the components listed in § 98.232(d)(7), you must conduct surveys as specified in paragraphs (q)(1)(v)(A) and (B) of this section and you must calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section.
(A) For the components listed in § 98.232(d)(7) that are not subject to the equipment leak standards in [reference to equipment leak standards for processing plants in 40 CFR part 60, subpart OOOOb] or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you may use any of the leak detection methods listed in § 98.234(a).
(B) For the components listed in § 98.232(d)(7) that are subject to the equipment leak standards in [reference to equipment leak standards for processing plants in 40 CFR part 60, subpart OOOOb] or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must use either of the leak detection methods in § 98.234(a)(1)(iii) or (2)(ii).
(vi) Except as provided in paragraph (q)(1)(vii) of this section, you must conduct at least one complete leak detection survey in a calendar year. If you conduct multiple complete leak detection surveys in a calendar year, you must use the results from each complete leak detection survey when calculating emissions using the procedures specified in either paragraph (q)(2) or (3) of this section. Except as provided in paragraphs (q)(1)(v)(A) through (G) of this section, a complete leak detection survey is a survey in which all equipment components required to be surveyed as specified in paragraphs (q)(1)(i) through (v) of this section are surveyed.
(A) For components subject to the well site and compressor station fugitive emissions standards in § 60.5397a of this chapter, each survey conducted in accordance with § 60.5397a of this chapter will be considered a complete leak detection survey for purposes of this section.
(B) For components subject to the well site and compressor station fugitive emissions standards in [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb], each survey conducted in accordance with [reference to fugitive emissions standards for well sites and compressor stations in 40 CFR part 60, subpart OOOOb] will be considered a complete leak detection survey for purposes of this section.