MEMORANDUM

To: Docket # EPA-HQ-OAR-2011-0512

From: Mark de Figueiredo, EPA/CCD

Date: November 10, 2014

Subject: Minor Technical Corrections to Subpart W, Greenhouse Gas Reporting Rule: 

2014 Revisions and Confidentiality Determinations for Petroleum and Natural 

Gas Systems; Final Rule

The EPA is finalizing revisions to the petroleum and natural gas systems source category 

of the Greenhouse Gas Reporting Rule (40 CFR part 98, subpart W). The changes revise 

calculation methods, amend monitoring and data reporting requirements, clarify certain terms 

and definitions, and correct technical and editorial errors identified during the course of 

implementation. 

The purpose of this memorandum is to provide a detailed list of minor or clarifying 

changes that are not discussed in the preambles to either the final or proposed amendments to 

subpart W (“Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Final Rule”). Table 1 contains a list of 

the minor changes, the current rule language for the requirement, and the revised rule language. 

An explanation for the change is included. These changes are minor clarifications to better 

reflect the EPA’s intent and include simple corrections to calculation terms or cross-references 

that do not revise the output of the calculations, harmonizing changes within the subpart (such as 

changes to terminology), simple editorial and minor error corrections, or removal of redundant 

text. Revisions to the reporting section of subpart W are not included in this memorandum, but 

are discussed in a separate document included in this docket entitled, “Final Revisions to the 

Subpart W Reporting Requirements in the Greenhouse Gas Reporting Rule: 2014 Revisions and 

Confidentiality Determinations for Petroleum and Natural Gas Systems; Final Rule.”

1
Table 1. Minor Technical Corrections

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.232(c)(11), 

(d)(1), (e)(1), 

(f)(1),(g)(1), (h)(1)

Reciprocating compressor rod 

packing venting.

Reciprocating compressor 

venting.

Harmonizing edit

§98.232(i)(1) (1) Meters, regulators, and 

associated equipment at 

above grade transmissiondistribution transfer stations, 

including equipment leaks 

from connectors, block 

valves, control valves, 

pressure relief valves, orifice 

meters, regulators, and open 

ended lines.

(1) Equipment leaks from 

connectors, block valves, 

control valves, pressure relief 

valves, orifice meters, 

regulators, and open-ended 

lines at above grade 

transmission-distribution 

transfer stations.

Clarifying edit

§98.232(i)(2) and 

(i)(4)

(2) Equipment leaks from 

vaults at...

(2) Equipment leaks at... Clarifying edit

§98.232(i)(3) (3) Meters, regulators, and 

associated equipment at 

above grade meteringregulating station.

(3) Equipment leaks at above 

grade metering-regulating 

stations that are not above 

grade transmission-distribution 

transfer stations.

Clarifying edit

§98.232(i)(5) (5) Pipeline main equipment 

leaks.

(5) Distribution main 

equipment leaks.

Clarifying edit

§98.232(i)(6) (6) Service line equipment 

leaks.

(6) Distribution services 

equipment leaks.

Clarifying edit

§98.233 throughout Methodologies Methods Clarifying edit

CEMS Continuous emissions 

monitoring system (CEMS)

Clarifying edit

General Stationary Fuel 

Combustion

General Stationary Fuel 

Combustion Sources

Clarifying edit

§98.233(a) and (c) Equation W-1 and W-2 

calculate mass emissions in 

CO2e. 

Removed term “Convi” so that

Equations W-1 and W-2 

calculate volumetric emissions 

instead of mass emissions in 

CO2e.

Global warming 

potential for methane 

removed from 

calculation.

2
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(a) and (c) 

introductory 

paragraphs

(a) Natural gas pneumatic 

device venting. Calculate CH4

and CO2 emissions from 

continuous high bleed, 

continuous low bleed, and 

intermittent bleed natural gas 

pneumatic devices using 

Equation W-1 of this section.

(a) Natural gas pneumatic 

device venting. Calculate CH4

and CO2 volumetric emissions 

from continuous high bleed, 

continuous low bleed, and 

intermittent bleed natural gas 

pneumatic devices using 

Equation W-1 of this section.

Clarified that 

calculated results in 

both paragraphs are 

volumetric emissions, 

and additional 

clarifying edit in 

paragraph (c).

(c) Natural gas driven 

pneumatic pump venting. 

Calculate CH4 and CO2

emissions from natural gas 

driven pneumatic pump 

venting using Equation W-2 

of this section. Natural gas 

driven pneumatic pumps 

covered in paragraph (e) of 

this section do not have to 

report emissions under 

paragraph (c) of this section.

(c) Natural gas driven 

pneumatic pump venting. 

Calculate CH4 and CO2

volumetric emissions from 

natural gas driven pneumatic 

pump venting using Equation 

W-2 of this section. Natural 

gas driven pneumatic pumps 

covered in paragraph (e) of this 

section do not have to report 

emissions under this paragraph 

(c).

§98.233(a) and (c); 

Terms Masst,i” in 

Equation W-1and 

“Massi” in Equation 

W-2

Masst,i = Annual total mass 

GHG emissions in metric tons 

CO2e per year from a natural 

gas pneumatic device vent of 

type “t,” for GHGi.

(Eq. W-1) 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.

Changed equation 

terms from “Masst,i”

(Equation W-1) and

“Massi” (Equation W2) to “Es,i” and revised 

units from mass to 

volumetric at standard 

conditions (EPA is 

revising the reporting 

of annual emissions 

from each source from 

units of metric tons of 

CO2e to metric tons of 

each reported GHG).

Massi = Annual total mass 

GHG emissions in metric tons 

CO2e per year from all natural 

gas pump venting, for GHGi.

(Eq. W-2) 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.

§98.233(a) and (c); 

Terms “Tt” in 

Equation W-1 and 

“T” in Equation 

W-2

Tt = Average estimated 

number of hours in the 

operating year the devices, of 

each type t, were operational. 

Default is 8760 hours.

Tt = Average estimated number 

of hours in the operating year 

the devices, of each type “t,”

were operational using 

engineering estimates based on 

best available data. Default is 

8760 hours.

Clarifying edit

T = Average estimated 

number of hours in the 

operating year the pumps 

were operational. Default is 

8760 hours.

T = Average estimated number 

of hours in the operating year 

the pumps were operational 

using engineering estimates 

based on best available data. 

Default is 8760 hours.

3
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233 (a) and (c); 

Term “EFt” in 

Equation W-1 and 

“EF” in Equation 

W-2

EFt = Population emission 

factors for natural gas 

pneumatic device venting 

listed in Tables...

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...

Clarifying edit

EF = Population emissions

factors for natural gas 

pneumatic pump venting

listed in Tables...

EF = Population emissions 

factors for natural gas driven 

pneumatic pumps (in standard 

cubic feet per hour per pump) 

listed in Table...

§98.233(c); Term 

“Count” in 

Equation W-2

Count = Total number of 

natural gas pneumatic pumps

Count = Total number of 

natural gas driven pneumatic 

pumps.

Clarifying edit

§98.233(a)(4) and 

(c)(2)

None Calculate both CH4 and CO2

mass emissions from 

volumetric emissions using 

calculations in paragraph (v) of 

this section.

Added (a)(4) and 

(c)(2) to convert 

volumetric to mass 

emissions.

§98.233(d)(2)

Term “VolCO2” in 

Equation W-3

VolCO2 = Volume fraction of 

CO2 content in vent gas out of 

the AGR unit as determined 

in (d)(6) of this section. 

VolCO2 = Annual average 

volumetric fraction of CO2

content in vent gas flowing out 

of the AGR unit as determined 

in paragraph (d)(6) of this 

section. 

Clarified that the term 

should be an annual 

average 

§98.233(d)(3)

Term “VolI” in 

Equations W-4A 

and W-4B

VolI = Volume fraction of 

CO2 content in natural gas 

into the AGR unit...

VolI = Annual average 

volumetric fraction of CO2

content in natural gas flowing 

into the AGR unit...

Clarified that the term 

should be an annual 

average

§98.233(d)(3); 

Term “Volo” in 

Equations W-4A 

and W-4B

Volo = Volume fraction of 

CO2 content in natural gas out 

of the AGR unit...

Volo = Annual average 

volumetric fraction of CO2

content in natural gas flowing 

out of the AGR unit...

Clarified that the term 

should be an annual 

average

§98.233(d)(4) AspenTech HYSYS®, and

API 4679 AMINECalc

AspenTech HYSYS®, or API 

4679 AMINECalc

Clarifying edit

§98.233(d)(5) Record the gas flow rate of 

the inlet and outlet natural gas 

stream of an AGR unit...

For Calculation Method 3, 

determine the gas flow rate of 

the inlet when using Equation 

W-4A of this section or the gas 

flow rate of the outlet when 

using Equation W-4B of this 

section for the natural gas 

stream of an AGR unit...

Clarified instructions 

so that they refer to 

specific equations and 

calculation methods 

4
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(d)(6) If continuous gas analyzer is 

not available on the vent 

stack, either install a 

continuous gas analyzer or 

take quarterly gas samples 

from the vent gas stream to 

determine VolCO2 according 

to methods set forth in 

§98.234(b).

For Calculation Method 2, if a 

continuous gas analyzer is not 

available on the vent stack, 

either install a continuous gas 

analyzer or take quarterly gas 

samples from the vent gas 

stream for each quarter that the 

AGR unit is operating to 

determine VolCO2 in Equation 

W-3 of this section according 

to the methods set forth in 

§98.234(b).

§98.233(d)(7) If a continuous gas analyzer is 

installed on the inlet gas 

stream, then the continuous 

gas analyzer results must be 

used. If continuous gas 

analyzer is not available, 

either install a continuous gas 

analyzer or take quarterly gas 

samples from the inlet gas

stream to determine VolI

according to methods set 

forth in §98.234(b).

For Calculation Method 3, if a 

continuous gas analyzer is 

installed on the inlet gas 

stream, then the continuous gas 

analyzer results must be used. 

If a continuous gas analyzer is 

not available, either install a 

continuous gas analyzer or take 

quarterly gas samples from the 

inlet gas stream for each 

quarter that the AGR unit is 

operating to determine VolI in 

Equation W-4A or W-4B of 

this section, according to the 

methods set forth in 

§98.234(b).

§98.233(d)(8) Determine volume fraction of 

CO2 content in natural gas out 

of the AGR unit using one of 

the methods specified in 

paragraph (d)(8) of this 

section.

For Calculation Method 3, 

determine annual average 

volumetric fraction of CO2

content in natural gas flowing 

out of the AGR unit using one 

of the methods specified in 

paragraphs (d)(8)(i) through 

(d)(8)(iii) of this section.

§98.233(d)(8)(ii) (ii) If a continuous gas 

analyzer is not available or 

installed, quarterly gas 

samples may be taken from 

the outlet gas stream to 

determine VolO according to 

methods set forth in 

§98.234(b).

(ii) If a continuous gas 

analyzer is not available or 

installed, quarterly gas samples 

may be taken from the outlet 

gas stream for each quarter that 

the AGR unit is operating to 

determine VolO in Equation W4A or W-4B of this section,

according to the methods set 

forth in §98.234(b).

Clarifying edits

5
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(d)(8)(iii) Use sales line quality 

specification for CO2 in 

natural gas.

If a continuous gas analyzer is 

not available or installed, you 

may use sales line quality 

specification for CO2 in natural 

gas. 

Clarifying edit 

§98.233(d)(9) Calculate CO2 volumetric 

emissions at standard 

conditions using calculations 

in paragraph (t) of this 

section. 

Calculate annual volumetric 

CO2 emissions at standard 

conditions using calculations in 

paragraph (t) of this section.

Clarified that the 

result is annual 

emissions. 

§98.233(d)(10) Mass CO2 emissions shall be 

calculated from volumetric 

CO2 emissions using 

calculations in paragraph (v) 

of this section. 

Calculate annual mass CO2

emissions using calculations in 

paragraph (v) of this section. 

Clarified that the 

result is annual 

emissions.

§98.233(d)(11) Determine if emissions from 

the AGR unit are recovered 

and transferred outside the 

facility. Adjust the emission

estimated in paragraphs (d)(1) 

through (d)(10) of this section 

downward by the magnitude 

of emission recovered and 

transferred outside the 

facility. 

Determine if CO2 emissions 

from the AGR unit are 

recovered and transferred 

outside the facility. Adjust the 

CO2 emissions estimated in 

paragraphs (d)(1) through 

(d)(10) of this section 

downward by the magnitude of 

CO2 emissions recovered and 

transferred outside the facility. 

Clarifying edit

6
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(e)(1) (1) Calculation Methodology 

1. Calculate annual mass 

emissions from dehydrator 

vents with annual average 

daily throughput greater than 

or equal to 0.4 million 

standard cubic feet per day 

using a software program, 

such as AspenTech HYSYS® 

or GRI-GLYCalc, that uses 

the Peng-Robinson equation 

of state to calculate the 

equilibrium coefficient, 

speciates 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. A 

minimum of the following 

parameters determined by 

engineering estimate based on 

best available data must be 

used to characterize emissions 

from dehydrators:

(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® 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. 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:

Clarifying edits

§98.233(e)(1)(iv) (iv) Absorbent circulation 

pump type (natural gas 

pneumatic/air 

pneumatic/electric).

(iv) Absorbent circulation 

pump type (e.g., natural gas 

pneumatic/air 

pneumatic/electric).

Clarifying edit

§98.233(e)(1)(vi) (vi) Absorbent type: including 

triethylene glycol (TEG), 

diethylene glycol (DEG) or 

ethylene glycol (EG).

(vi) Absorbent type (e.g., 

triethylene glycol (TEG), 

diethylene glycol (DEG) or 

ethylene glycol (EG)).

Clarifying edit

7
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(e)(1)(xi), 

(e)(1)(xi)(A), and 

(e)(1)(xi)(B)

xi) Wet natural gas 

composition. Determine this 

parameter by selecting one of 

the methods described under 

paragraph (e)(1)(xi) of this 

section.

(xi) Wet natural gas 

composition. Determine this 

parameter using one of the 

methods described in 

paragraphs (e)(1)(xi)(A) 

through (e)(1)(xi)(D) of this 

section.

Harmonizing edit

(A) Use the wet natural gas 

composition as defined in 

paragraph (u)(2)(i) or 

(u)(2)(ii) of this section.

(A) Use the GHG mole 

fraction as defined in 

paragraph (u)(2)(i) or (u)(2)(ii) 

of this section.

(B) If wet natural gas 

composition cannot be 

determined using paragraph 

(u)(2)(i) or (u)(2)(ii) of this 

section, select a 

representative analysis.

(B) If the GHG mole fraction 

cannot be determined using 

paragraph (u)(2)(i) or (u)(2)(ii) 

of this section, select a 

representative analysis.

§98.233(e)(2) (2) Calculation Methodology 

2. Calculate annual CH4 and 

CO2 emissions from glycol 

dehydrators with annual 

average daily throughput less 

than 0.4 million standard 

cubic feet per day using 

Equation W-5 of this section:

(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:

Clarifies that result is 

annual volumetric 

emissions.

Term “Count” in 

Equation W-5

Count = Total number of 

glycol dehydrators with 

throughput less than 0.4 

million standard cubic feet 

per day.

Count = Total number of 

glycol dehydrators that have an 

annual average of daily natural 

gas throughput that is less than 

0.4 million standard cubic feet 

per day.

Clarifying edits

Term “P” in 

Equation W-6

P π Corrects typo (to 

Greek letter).

§98.233(f) (f) Well venting for liquids 

unloadings. Calculate CO2

and CH4 emissions from well 

venting for liquids unloading 

using one of the calculation 

methodologies described in 

paragraphs (f)(1), (f)(2) or 

(f)(3) of this section.

(f) Well venting for liquids 

unloadings. Calculate annual 

volumetric natural gas 

emissions from well venting 

for liquids unloading using one 

of the calculation methods 

described in paragraphs (f)(1), 

(f)(2), or (f)(3) of this section. 

Calculate annual CH4 and CO2

volumetric and mass emissions 

using the method described in 

paragraph (f)(4) of this section.

Clarifies that results of 

(f)(1), (f)(2), and (f)(3) 

are annual volumetric 

natural gas emissions 

and provides (f)(4) for 

calculation of annual 

CH4 and CO2

volumetric and mass 

emissions.

8
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(f)(1)(i) (i) Determine the well vent 

average flow rate as specified 

under paragraph (f)(1)(i) of 

this section for at least one 

well in a unique well tubing 

diameter group and pressure 

group combination in each 

sub-basin category. 

(i) Determine the well vent 

average flow rate (“FR” in 

Equation W-7A of this section) 

as specified in paragraphs 

(f)(1)(i)(A) through (f)(1)(i)(C) 

of this section for at least one 

well in a unique well tubing 

diameter group and pressure 

group combination in each 

sub-basin category. Calculate 

emissions from wells with 

plunger lifts and wells without 

plunger lifts separately.

Clarifies instructions 

so that they refer to 

specific equation 

terms and calculation 

methods

§98.233(f)(1)(i)(A) (A) The average flow rate per 

hour of venting is calculated 

for each unique tubing 

diameter group and pressure 

group combination in each 

sub-basin category by 

dividing the recorded total 

flow by the recorded time (in 

hours) for all measured liquid 

unloading events with venting 

to the atmosphere.

(A) Calculate the average flow 

rate per hour of venting for 

each unique tubing diameter 

group and pressure group 

combination in each sub-basin 

category by dividing the 

recorded total annual flow by 

the recorded time (in hours) for 

all measured liquid unloading 

events with venting to the 

atmosphere.

Clarifies that recorded 

total flow is total 

annual flow.

§98.233(f)(1)(i)(B) (B) This average flow rate per 

hour is applied to all wells in 

the same pressure group that 

have the same tubing 

diameter group, for the 

number of hours of venting 

these wells.

(B) Apply the average hourly 

flow rate calculated under 

paragraph (f)(1)(i)(A) of this 

section to all wells in the same 

pressure group that have the 

same tubing diameter group, 

for the number of hours of 

venting these wells.

Clarifying edits

§98.233(f)(1)(i)(C) (C) A new average flow rate 

is calculated every other 

calendar year for each 

reporting sub-basin category 

starting the first calendar year 

of data collection. For a new 

producing sub-basin category, 

an average flow rate is 

calculated beginning in the 

first year of production.

(C) Calculate a new average 

flow rate every other calendar 

year starting with the first 

calendar year of data 

collection. For a new 

producing sub-basin category, 

calculate an average flow rate 

beginning in the first year of 

production.

Harmonizing edit with 

changes to term “FR”

in Equation W-7.

§98.233(f)(2) and 

(f)(3); Term “Es,n”

of Equations W-8 

and W-9

Es,n = Annual natural gas 

emissions at standard 

conditions, in cubic feet/year.

Es = Annual natural gas 

emissions for each sub-basin at 

standard conditions, s, in cubic 

feet per year.

Clarifying edits

9
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(f)(2) and 

(f)(3); Terms “p”

and “q” of 

Equations W-8 and 

W-9

None p = Wells 1 through W with 

well venting for liquids 

unloading for each sub-basin.

...

q = Unloading event.

Clarifies terms not 

previously defined

§98.233(f)(2) and 

(f)(3); Term “Vp” of 

Equations W-8 and 

W-9

Vp = Number of unloading 

events per year per well, p.

Vp = Total number of 

unloading events in the 

monitoring period per well, p.

Corrects equation term 

to reflect the number 

of unloading events in 

each monitoring 

period.

§98.233(f)(2) and 

(f)(3); Term “SFRp”

of Equations W-8 

and W-9

SFRp = Average flow-line 

rate of gas for well, p, at 

standard conditions in cubic 

feet per hour. Use Equation 

W-33 to calculate the average 

flow-line rate at standard 

conditions.

SFRp = Average flow-line rate 

of gas for well, p, at standard 

conditions in cubic feet per 

hour. Use Equation W-33 of 

this section to calculate the 

average flow-line rate at 

standard conditions.

Clarifying edit

§98.233(f)(3)(i) and 

(ii)

Reserved None Removes reserved 

paragraphs 

§98.233(f)(4) (4) Both CH4 and CO2

volumetric and mass 

emissions shall be calculated 

from volumetric natural gas 

emissions using calculations 

in paragraphs (u) and (v) of 

this section.

(4) Calculate CH4 and CO2

volumetric and mass emissions 

from volumetric natural gas 

emissions using calculations in 

paragraphs (u) and (v) of this 

section.

Applies active voice

§98.233(g) 

introductory 

paragraph; 

§98.233(g)(3)

(g) Gas well venting during 

completions and workovers 

from hydraulic fracturing.

Calculate CH4, CO2 and N2O 

annual emissions from gas 

well venting during 

completions involving 

hydraulic fracturing in wells 

and well workovers using 

Equation W-10A or Equation 

W-10B of this section. 

Equation W-10A applies to 

well venting when the 

backflow rate is measured or 

calculated, Equation W-10B 

applies when the backflow 

vent or flare volume is 

measured. Use Equation W10A if the flow rate for 

backflow during well 

completions and workovers 

from hydraulic fracturing is 

known for the specified 

(g) Gas well venting during 

completions and workovers 

with hydraulic fracturing.

Calculate annual volumetric 

natural gas emissions from gas 

well venting during 

completions and workovers 

involving hydraulic fracturing 

using Equation W-10A or 

Equation W-10B of this 

section. Equation W-10A 

applies to well venting when 

the flowback rate is measured 

from a specified number of 

example completions or 

workovers and Equation W10B applies when the flowback 

vent or flare volume is 

measured for each completion 

or workover. Completion and 

workover activities are 

separated into two periods, an 

initial period when flowback is 

Clarifies instructions; 

clarifies that results of 

(g)(1) and (g)(2) are 

annual volumetric 

natural gas emissions 

and clarifies (g)(3) for 

calculation of annual 

CH4 and CO2 

volumetric and mass 

emissions.

10
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

number of wells per 

paragraph (g)(1) in a subbasin and well type 

(horizontal or vertical) 

combination. Use Equation 

W-10B if the flow volume for 

backflow during well 

completions and workovers 

from hydraulic fracturing is 

known for all wells in a subbasin and well type 

(horizontal or vertical) 

combination. Both CH4 and 

CO2 volumetric and mass 

emissions shall be calculated 

from volumetric total gas 

emissions using calculations 

in paragraphs (u) and (v) of 

this section.

routed to open pits or tanks and 

a subsequent period when gas 

content is sufficient to route 

the flowback to a separator or 

when the gas content is 

sufficient to allow 

measurement by the devices 

specified in paragraph (g)(1) of 

this section, regardless of 

whether a separator is actually 

utilized. If you elect to use 

Equation W-10A of this 

section, you must follow the 

procedures specified in 

paragraph (g)(1) of this 

section. Emissions must be 

calculated separately for 

completions and workovers, 

for each sub-basin, and for 

each well type combination 

identified in paragraph (g)(2) 

of this section. You must 

calculate CH4 and CO2

volumetric and mass emissions 

as specified in paragraph (g)(3) 

of this section. If emissions 

from gas well venting during 

completions and workovers 

with hydraulic fracturing are 

routed to a flare, you must 

calculate CH4, CO2, and N2O 

annual emissions as specified 

in paragraph (g)(4) of this 

section.

Term “Es,n” in 

Equations W-10A 

and W-10B

Es,n = Annual volumetric total 

gas emissions in cubic feet at 

standard conditions from gas 

well venting during 

completions or workovers 

following hydraulic fracturing 

for each sub-basin and well 

type (horizontal vs. vertical) 

combination.

Es,n = Annual volumetric

natural gas emissions in 

standard cubic feet from gas 

well venting during 

completions or workovers 

following hydraulic fracturing 

for each sub-basin and well 

type combination.

Clarifying edits

Term “W” in 

equations W-10A 

and W-10B

W = Total number of wells 

completed or worked over 

using hydraulic fracturing in a 

sub-basin and well type 

(horizontal vs. vertical) 

combination.

W = Total number of wells 

completed or worked over 

using hydraulic fracturing in a 

sub-basin and well type 

combination.

Clarifying edits

11
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

Term “FRMs” of 

Equation W-10A

FRMs = Ratio of flowback 

during well completions and 

workovers from hydraulic 

fracturing to 30-day 

production rate from Equation 

W-12.

FRMs = Ratio of average 

flowback, during the period 

when sufficient quantities of 

gas are present to enable 

separation, of well completions 

and workovers from hydraulic 

fracturing to 30-day production 

rate for the sub-basin and well 

type combination, calculated 

using procedures specified in 

paragraph (g)(1)(iii) of this 

section, expressed in standard 

cubic feet per hour.

Harmonizing edits 

with changes to 

Equation W-10A

Term “EnFs,p” in 

equations W-10A 

and W-10B

EnFs,p = Volume of CO2 or N2

injected gas in cubic feet at 

standard conditions that was 

injected into the reservoir 

during an energized fracture 

job for each well p. If the 

fracture process did not inject 

gas into the reservoir, then 

EnFs,p is 0. If injected gas is 

CO2 then EnFs,p is 0.

EnFs,p = Volume of N2 injected 

gas in cubic feet at standard 

conditions that was injected 

into the reservoir during an 

energized fracture job for each 

well, p, as determined by using 

an appropriate meter according 

to methods described in 

§98.234(b), or by using 

receipts of gas purchases that 

are used for the energized 

fracture job. Convert to 

standard conditions using 

paragraph (t) of this section. If 

the fracture process did not 

inject gas into the reservoir or 

if the injected gas is CO2 then 

EnFs,p is 0.

Clarifies acceptable 

measurement methods

12
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(g)(1)(i) Calculation Methodology 1.

When using Equation W10A, for each measured well 

completion(s) in each gas 

producing sub-basin category 

and well type (horizontal or 

vertical) combination and for 

each measured well 

workover(s) in each gas 

producing sub-basin category 

and well type (horizontal or 

vertical) combination, a 

recording flow meter (digital 

or analog) shall be installed 

on the vent line, ahead of a 

flare or vent if used, to 

measure the backflow rate 

according to methods set 

forth in §98.234(b).

Calculation Method 1. You 

must use Equation W-12A as 

specified in paragraph 

(g)(1)(iii) of this section to 

determine the value of FRMs. 

You must use Equation W-12B 

as specified in paragraph 

(g)(1)(iv) of this section to 

determine the value of FRMi. 

The procedures specified in 

paragraphs (g)(1)(v) and 

(g)(1)(vi) also apply. When 

making flowback 

measurements for use in 

Equations W-12A and W-12B 

of this section, you must use a 

recording flow meter (digital

or analog) installed on the vent 

line, ahead of a flare or vent, to 

measure the flowback rates in 

units of standard cubic feet per 

hour according to methods set 

forth in §98.234(b).

Harmonizing changes 

with edits to Equation 

W-10A

§98.233(g)(1)(ii) (ii) Calculation Methodology 

2. When using Equation W10A, for each calculated 

horizontal well completion 

and each calculated vertical 

well completion in each gas 

producing sub-basin category 

and for each calculated well 

horizontal workover and for 

each calculated vertical well 

workover in each gas 

producing sub-basin category, 

record the well flowing 

pressure upstream (and 

downstream in subsonic flow) 

of a well choke according to 

methods set forth in 

§98.234(b) to calculate the 

well backflow during well 

completions and workovers 

from hydraulic fracturing. 

Calculate emissions using 

Equation W-11A of this 

section for subsonic flow or 

Equation W-11B of this 

section for sonic flow. Use 

best engineering estimate 

based on best available data 

(ii) Calculation Method 2. You 

must use Equation W-12A as 

specified in paragraph 

(g)(1)(iii) of this section to 

determine the value of FRMs. 

You must use Equation W-12B 

as specified in paragraph 

(g)(1)(iv) of this section to 

determine the value of FRMi. 

The procedures specified in 

paragraphs (g)(1)(v) and 

(g)(1)(vi) also apply. When 

calculating the flowback rates 

for use in Equations W-12A 

and W-12B of this section 

based on well parameters, you 

must record the well flowing 

pressure immediately upstream 

(and immediately downstream 

in subsonic flow) of a well 

choke according to methods set 

forth in §98.234(b) to calculate 

the well flowback. The 

upstream pressure must be 

surface pressure and reservoir 

pressure cannot be assumed. 

The downstream pressure must 

be measured after the choke 

Harmonizing changes 

with edits to Equation 

W-10A

13
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

along with Equation W-11C 

of this section to determine 

whether the predominant flow 

is sonic or subsonic. If the 

value of R in Equation W11C is greater than or equal to 

2, then flow is sonic; 

otherwise, flow is subsonic.

and atmospheric pressure 

cannot be assumed. Calculate 

flowback rate using Equation 

W-11A of this section for 

subsonic flow or Equation W11B of this section for sonic 

flow. You must use best 

engineering estimates based on 

best available data along with 

Equation W-11C of this 

section to determine whether 

the predominant flow is sonic 

or subsonic. If the value of R 

in Equation W-11C of this 

section is greater than or equal 

to 2, then flow is sonic; 

otherwise, flow is subsonic. 

Convert calculated FRa values 

from actual conditions 

upstream of the restriction 

orifice to standard conditions 

(FRs,p and FRi,p) for use in 

Equations W-12A and W-12B 

of this section using Equation 

W-33 in paragraph (t) of this 

section.

Term “FRa” of 

Equations W-11A 

and W-11B

FRa = Average flow rate in 

cubic feet per hour, under 

actual subsonic flow 

conditions.

FRa = Flowback rate in actual 

cubic feet per hour, under 

actual subsonic flow 

conditions.

Harmonizing edits 

with changes to 

Equations W-12A and 

W-12B

Terms “P1,” “Tu,”

and “P2” of 

Equation W-11A

P1 = Upstream pressure 

(psia).

P1 = Pressure immediately 

upstream of the choke (psia).

Clarifying edits

Tu = Upstream temperature 

(degrees Kelvin).

Tu = Temperature immediately 

upstream of the choke (degrees 

Kelvin).

P2 = Downstream pressure 

(psia).

P2 = Pressure immediately 

downstream of the choke 

(psia).

Term “Tu” of 

Equation W-11B

Tu = Upstream temperature 

(degrees Kelvin).

Tu = Temperature immediately 

upstream of the choke (degrees 

Kelvin).

Clarifying edits

Terms “P1” and 

“P2” of Equation 

W-11C

P1 = Pressure upstream of the 

restriction orifice in pounds 

per square inch absolute.

P1 = Pressure immediately 

upstream of the choke (psia).

Clarifying edits

P2 = Pressure downstream of 

the restriction orifice in 

pounds per square inch 

absolute.

P2 = Pressure immediately 

downstream of the choke 

(psia).

14
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(g)(1)(iii) For Equation W-10A, the 

ratio of backflow rate during 

well completions and 

workovers from hydraulic 

fracturing to 30-day 

production rate is calculated 

using Equation W-12 of this 

section.

For Equation W-10A of this 

section, calculate FRMs using 

Equation W-12A of this 

section.

Harmonizing edits 

with changes to 

Equation W-10A

Terms “FRMs” and 

“FRs,p” of Equation 

W-12A

FRMs = Ratio of flowback 

rate during well completions 

and workovers from hydraulic 

fracturing to 30-day 

production rate.

FRMs = Ratio of average 

flowback rate, during the 

period of time when sufficient 

quantities of gas are present to 

enable separation, of well 

completions and workovers 

from hydraulic fracturing to 

30-day production rate for each 

sub-basin and well type 

combination.

Harmonizing edits 

with changes to 

Equation W-10A

FRs,p = Measured flowback

rate from Calculation 

Methodology 1 described in 

paragraph (g)(1)(i) of this 

section or calculated flow rate 

from Calculation 

Methodology 2 described in 

paragraph (g)(1)(ii) of this 

section in standard cubic feet 

per hour for well(s) p for each 

sub-basin and well type 

(horizontal or vertical) 

combination. Measured and 

calculated FRa values shall be 

converted from actual 

conditions (FRa) to standard 

conditions (FRs,p) for each 

well p using Equation W-33 

in paragraph (t) of this 

section. You may not use 

flow volume as used in 

Equation W-10B converted to 

a flow rate for this parameter.

FRs,p = Measured average 

flowback rate from Calculation 

Method 1 described in 

paragraph (g)(1)(i) of this 

section or calculated average 

flowback rate from Calculation 

Method 2 described in 

paragraph (g)(1)(ii) of this 

section, during the separation 

period in standard cubic feet 

per hour for well(s) p for each 

sub-basin and well type 

combination. Convert 

measured and calculated FRa

values from actual conditions 

upstream of the restriction 

orifice (FRa) to standard 

conditions (FRs,p) for each well 

p using Equation W-33 in 

paragraph (t) of this section. 

You may not use flow volume 

as used in Equation W-10B 

converted to a flow rate for this 

parameter.

15
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(g)(1)(iv) None For Equation W-10A of this 

section, calculate FRMi using 

Equation W-12B of this section.

,

1

,

1

N

i p

p

i N

s p

p

FR

FRM

PR

=

=

=

∑

∑

(Eq. W-12B)

Where:

FRMi = Ratio of flowback gas 

rate while flowing to open 

tanks/pits during well 

completions and workovers

from hydraulic fracturing to 30-

day production rate.

FRi,p = Initial measured gas 

flowback rate from Calculation 

Method 1 described in 

paragraph (g)(1)(i) of this 

section or initial calculated flow 

rate from Calculation Method 2 

described in paragraph (g)(1)(ii) 

of this section in standard cubic 

feet per hour for well(s), p, for 

each sub-basin and well type 

combination. Measured and 

calculated FRi,p values must be 

based on flow conditions at the 

beginning of the separation 

period and must be expressed at 

standard conditions.

PRs,p = Average production flow 

rate during the first 30-days of 

production after completions of 

newly drilled gas wells or gas 

well workovers using hydraulic 

fracturing, in standard cubic feet 

per hour of each well, p, that 

was measured in the sub-basin 

and well type combination.

N = Number of measured or 

calculated well completions or 

workovers using hydraulic 

fracturing in a sub-basin and 

well type combination.

Harmonizing edits

with changes to 

Equation W-10A

16
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(g)(1)(v) 

and (vi)

(iv) For Equation W-10A, the 

ratio of backflow rate during 

well completions and 

workovers from hydraulic 

fracturing to 30-day 

production rate for horizontal 

and vertical wells are applied 

to all horizontal and vertical 

well completions in the gas 

producing sub-basin and well 

type combination and to all 

horizontal and vertical well 

workovers, respectively, in 

the gas producing sub-basin 

and well type combination for 

the total number of hours of 

backflow for each of these 

wells.

(v) For Equation W-10A of

this section, the ratio of 

flowback rate during well 

completions and workovers 

from hydraulic fracturing to 

30-day production rate for 

horizontal and vertical wells 

are applied to all horizontal 

and vertical well completions 

in the gas producing sub-basin

and well type combination and 

to all horizontal and vertical 

well workovers, respectively, 

in the gas producing sub-basin 

and well type combination for 

the total number of hours of 

flowback and for the first 30 

day average production rate for 

each of these wells.

Renumbered and 

revised to harmonize 

with edits to Equation 

W-10A

(v) For Equation W-10A, new 

flow rates for horizontal and 

vertical gas well completions 

and horizontal and vertical 

gas well workovers in each 

sub-basin category shall be 

calculated once every two 

years starting in the first 

calendar year of data 

collection.

(vi) For Equation W-12A and 

W-12B of this section, 

calculate new flowback rates 

for horizontal and vertical gas 

well completions and 

horizontal and vertical gas well 

workovers in each sub-basin 

category once every two years 

starting in the first calendar 

year of data collection.

17
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(g)(4) (5) Calculate annual 

emissions from gas well 

venting during well 

completions and workovers

from hydraulic fracturing to 

flares as follows:

(4) Calculate annual emissions 

from gas well venting during 

well completions and 

workovers from hydraulic 

fracturing where all or a 

portion of the gas is flared as 

specified in paragraphs 

(g)(4)(i) and (g)(4)(ii) of this 

section.

Renumbered; clarifies 

calculation method 

where a portion of the 

gas is flared

(i) Use total gas well venting 

volume during well 

completions and workovers as 

determined in paragraph (g) 

of this section.

(i) Use the volumetric total 

natural gas emissions vented to 

the atmosphere during well 

completions and workovers as 

determined in paragraph (g) of 

this section to calculate 

volumetric and mass emissions 

using paragraphs (u) and (v) of 

this section.

(ii) Use the calculation 

methodology of flare stacks 

in paragraph (n) of this 

section to determine gas well 

venting during well 

completions and workovers 

using hydraulic fracturing 

emissions from the flare. This 

adjustment to emissions from 

completions using flaring 

versus completions without 

flaring accounts for the 

conversion of CH4 to CO2 in 

the flare.

(ii) Use the calculation method 

of flare stacks in paragraph (n) 

of this section to adjust 

emissions for the portion of gas 

flared during well completions

and workovers using hydraulic 

fracturing. This adjustment to 

emissions from completions 

using flaring, versus 

completions without flaring, 

accounts for the conversion of 

CH4 to CO2 in the flare and for 

the formation on N2O during 

flaring.

18
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(h) 

introductory 

paragraph

Calculate CH4, CO2 and N2O 

emissions from each gas well 

venting during well 

completions and workovers 

and not involving hydraulic 

fracturing using Equation W13 of this section. 

Calculate annual volumetric 

natural gas emissions from

each gas well venting during 

workovers without hydraulic 

fracturing using Equation W13A of this section. Calculate 

annual volumetric natural gas 

emissions from each gas well 

venting during completions 

without hydraulic fracturing 

using Equation W-13B of this 

section. You must convert 

annual volumetric natural gas 

emissions to CH4 and CO2

volumetric and mass emissions 

as specified in paragraph (h)(1) 

of this section. If emissions 

from gas well venting during 

completions and workovers

without hydraulic fracturing 

are routed to a flare, you must 

calculate CH4, CO2, and N2O 

annual emissions as specified 

in paragraph (h)(2) of this 

section.

Edits clarify 

instructions; clarifies 

that results of 

Equations W-13A and 

W-13B are annual 

volumetric natural gas 

emissions

Term “Tp” of 

Equation W-13

Tp = Time each well 

completion without hydraulic 

fracturing, p, was venting in 

hours during the year.

Tp = Time that gas is vented to 

either the atmosphere or a flare 

for each well, p, undergoing 

completion without hydraulic 

fracturing, in hours during the 

year.

Clarifying edits

§98.233(h)(1) (1) Volumetric emissions for 

both CH4 and CO2 shall be 

calculated from volumetric 

natural gas emissions using 

calculations in paragraph (u) 

of this section. Mass 

emissions for both CH4 and

CO2 shall be calculated from 

volumetric natural gas 

emissions using calculations 

in paragraphs (v) of this 

section.

(1) Calculate both CH4 and

CO2 volumetric emissions 

from natural gas volumetric 

emissions using calculations in 

paragraph (u) of this section. 

Calculate both CH4 and CO2

mass emissions from 

volumetric emissions vented to 

the atmosphere using 

calculations in paragraph (v) of 

this section.

Clarifies calculation of 

annual CH4 and CO2 

volumetric and mass 

emissions

19
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(h)(2) (2) Calculate annual 

emissions from gas well 

venting during well 

completions and workovers 

not involving hydraulic 

fracturing to flares as follows:

(2) Calculate annual emissions 

of CH4, CO2, and N2O from 

gas well venting to flares 

during well completions and 

workovers not involving 

hydraulic fracturing as 

specified in paragraphs 

(h)(2)(i) and (h)(2)(ii) of this 

section.

Clarifying edits

(i) Use the gas well venting 

volume during well 

completions and workovers as 

determined in paragraph (h) 

of this section.

(i) Use the gas well venting 

volume and gas composition 

during well completions and 

workovers that are flared as 

determined using the methods 

specified in paragraphs (h) and 

(h)(1) of this section.

(ii) Use the calculation 

methodology of flare stacks 

in paragraph (n) of this 

section to determine gas well 

venting during well 

completions and workovers

emissions without hydraulic 

fracturing from the flare.

(ii) Use the calculation method 

of flare stacks in paragraph (n) 

of this section to determine 

emissions from the flare for 

gas well venting to a flare 

during completions and 

workovers without hydraulic 

fracturing.

20
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(i) Blowdown vent stacks.

Calculate CO2 and CH4

blowdown vent stack 

emissions from 

depressurizing equipment(s) 

to reduce system pressure for 

planned or emergency 

shutdowns resulting from 

human intervention or to take 

equipment out of service for 

maintenance (excluding 

depressurizing to a flare, 

over-pressure relief, operating 

pressure control venting and 

blowdown of non-GHG 

gases; desiccant dehydrator 

blowdown venting before 

reloading is covered in 

paragraph (e)(5) of this 

section) as follows:

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 (i)(3) 

of this section. You may use 

the method in paragraph (i)(2) 

of this section for some 

blowdown vent stacks at your 

facility and the method in 

paragraph (i)(3) of this section 

for other blowdown vent stacks 

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 (i)(4) 

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, blowdown of nonGHG gases, and desiccant 

dehydrator blowdown venting 

before reloading.

Clarifies that some 

blowdown emissions 

may be calculated 

using the unique 

physical volumes and 

equipment or event 

type method, while 

other blowdown 

emissions may be 

determined by using a 

flow meter. Also 

clarifies that

requirements in this 

section do not apply to 

equipment with a 

physical volume of 

less than 50 cubic feet

§98.233(i)(1) (1) Calculate the unique 

physical volume (including 

pipelines, compressor case or 

cylinders, manifolds, suction 

bottles, discharge bottles, and 

vessels) between isolation 

valves determined by 

engineering estimates based 

on best available data.

(1) Method for calculating 

unique physical volumes. You 

must calculate each unique 

physical volume (including 

pipelines, compressor case or 

cylinders, manifolds, suction 

bottles, discharge bottles, and 

vessels) between isolation 

valves, in cubic feet, by using 

engineering estimates based on 

best available data.

Clarifies measurement 

units

21
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

N/A (i)(2) If the unique physical 

volume between isolation 

valves is greater than or equal 

to 50 cubic feet, retain logs of 

the number of blowdowns for 

each unique physical volume 

(including but not limited to 

compressors, vessels, 

pipelines, headers, 

fractionators, and tanks). 

Unique physical volumes 

smaller than 50 cubic feet are 

exempt from reporting under 

paragraph (i) of this section.

None Harmonizing change 

with edits to Equations 

W-14A and W-14B

§98.233(i)(4) (4) Calculate both CH4 and 

CO2 volumetric and mass 

emissions using calculations 

in paragraph (u) and (v) of 

this section.

(4) Method for converting 

from natural gas emissions to 

GHG volumetric and mass 

emissions. Calculate both CH4

and CO2 volumetric and mass 

emissions using the methods 

specified in paragraphs (u) and 

(v) of this section.

Clarifying edits

§98.233(j) (j) ... not owned or operated 

by the reporter), calculate 

annual CH4 and CO2 

emissions using any of the 

calculation methodologies 

described in this paragraph 

(j). 

(1) Calculation Methodology 

1. For separators with annual 

average daily throughput of 

oil greater than or equal to 10 

barrels per day. Calculate...

(2) Calculation Methodology 

2. Calculate annual CH4 and 

CO2 emissions from onshore 

production storage tanks for 

wellhead gas-liquid 

separators with annual 

average daily throughput of 

oil greater than or equal to 10 

barrels per day by....

(3) Calculation Methodology 

3. For wells with annual 

average daily oil production 

greater than or equal to 10 

barrels per day that flow 

directly to atmospheric 

storage tanks without passing 

(j) ... not owned or operated 

by the reporter), as specified in 

this paragraph (j). For wells 

flowing to gas-liquid 

separators with annual average 

daily throughput of oil greater 

than or equal to 10 barrels per 

day, calculate annual CH4 and 

CO2 using Calculation Method 

1 or 2 as specified in 

paragraphs (j)(1) and (j)(2) of 

this section. For wells flowing 

directly to atmospheric storage 

tanks without passing through 

a wellhead separator with 

throughput greater than or 

equal to 10 barrels per day, 

calculate annual CH4 and CO2

emissions using Calculation 

Method 2 as specified in 

paragraph (j)(2) of this section. 

For wells flowing to gas-liquid 

separators or directly to 

atmospheric storage tanks with 

throughput less than 10 barrels 

per day, use Calculation 

Method 3 as specified in 

paragraph (j)(3) of this section. 

If you use Calculation Method 

Clarifies and 

consolidates 

instructions for use of 

calculation methods 

by removing and 

combining text from 

(j)(1) introductory, 

(j)(2) introductory, 

(j)(3) introductory, 

and (j)(4) paragraphs. 

Clarifies instructions 

in (j) intro to account 

for situations where 

part of the gas is 

recovered or flared

22
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

through a wellhead separator, 

calculate annual CH4 and CO2 

emissions by either of the 

methods in paragraph (j)(3) of 

this section: ...

(4) Calculation Methodology 

4. For wells with annual 

average daily oil production 

greater than or equal to 10 

barrels per day that flow to a 

separator not at the well pad, 

calculate annual CH4 and CO2 

emissions by either of the 

methods in paragraph (j)(4) of 

this section: ...

(5) Calculation Methodology 

5. For well pad gas-liquid 

separators and for wells 

flowing off a well pad 

without passing through a 

gas-liquid separator with 

annual average daily 

throughput of oil less than 10 

barrels per day use....

1 or 2, you must also calculate 

emissions that may have 

occurred due to dump valves 

not closing properly using the 

method specified in paragraphs 

(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.

§98.233(j)(1)(vii) (vii) Separator oil 

composition and Reid vapor 

pressure. If this data is not

available, determine these 

parameters by selecting one 

of the methods described 

under paragraph (j)(1) (vii) of 

this section.

(vii) Separator oil 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 (j)(1)(vii)(C) of this 

section.

Corrects reference

§98.233(j)(7) (9) ...emissions from 

volumetric natural gas 

emissions...

(7) ...emissions from natural 

gas volumetric emissions...

Grammatical 

correction and 

renumbered section

Term “En” in 

Equation W-16

Storage tank emissions as 

determined in Calculation 

Methods 1, 2, or 3 in 

paragraphs (j)(1), (j)(2) and 

(j)(3) of this section (with 

wellhead separators) in 

standard cubic feet per year.

Storage tank emissions as 

determined in paragraphs 

(j)(1), (j)(2) and, if applicable, 

(j)(4) of this section in standard 

cubic feet per year.

Clarifying edits

§98.233(l)(5) (5) ...emissions from 

volumetric natural gas 

emissions...

(5) ...emissions from natural 

gas volumetric emissions...

Grammatical 

correction

23
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(k), (l), and 

(m) introductory 

paragraphs

(k) .... calculate CH4, CO2

and N2O annual emissions 

from compressor scrubber 

dump valve leakage as 

follows.

(k) ... calculate CH4 and CO2

annual emissions from 

compressor scrubber dump 

valve leakage as specified in 

paragraphs (k)(1) through 

(k)(4) of this section. If 

emissions from compressor 

scrubber dump valve leakage 

are routed to a flare, you must 

calculate CH4, CO2, and N2O 

annual emissions as specified 

in paragraph (k)(5) of this 

section.

Clarifies instructions; 

clarifies N2O to be 

calculated from 

emissions routed to a 

flare

(l) .... Calculate CH4, CO2

and N2O (when flared) well 

testing venting and flaring 

emissions as follows:

(l) ... Calculate CH4 and CO2

annual emissions from well 

testing venting as specified in 

paragraphs (l)(1) through (l)(5) 

of this section. If emissions 

from well testing venting are 

routed to a flare, you must 

calculate CH4, CO2, and N2O 

annual emissions as specified 

in paragraph (l)(6) of this 

section.

(m) ... Calculate CH4, CO2

and N2O (when flared) 

associated gas venting and 

flaring emissions not in 

conjunction with well testing 

(refer to paragraph (l): Well 

testing venting and flaring of 

this section) as follows:

(m) ... Calculate CH4 and CO2

annual emissions from 

associated gas venting not in 

conjunction with well testing 

(refer to paragraph (l): Well 

testing venting and flaring of 

this section) as specified in 

paragraphs (m)(1) through 

(m)(4) of this section. If 

emissions from associated gas 

venting are routed to a flare, 

you must calculate CH4, CO2, 

and N2O annual emissions as 

specified in paragraph (m)(5) 

of this section.

24
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(k)(1) (k)(1) Monitor the tank vapor 

vent stack annually for 

emissions using an optical gas 

imaging instrument according 

to methods set forth in 

§98.234(a)(1) or by directly 

measuring the tank vent using 

a flow meter or high volume 

sampler according to methods 

in §98.234(b) through (d) for 

a duration of 5 minutes, or a 

calibrated bag according to 

methods in §98.234(b). Or 

you may annually monitor 

leakage through compressor 

scrubber dump valve(s) into 

the tank using an acoustic 

leak detection device 

according to methods set 

forth in §98.234(a)(5).

(1) Except as specified in 

paragraph (k)(1)(iv) of this 

section, you must monitor the 

tank vapor vent stack annually 

for emissions using one of the 

methods specified in 

paragraphs (k)(1)(i) through 

(k)(1)(iii) of this section.

(i) Use an optical gas imaging 

instrument according to 

methods set forth in 

§98.234(a)(1).

(ii) Measure the tank vent 

directly using a flow meter or 

high volume sampler according 

to methods in §98.234(b) or (d) 

for a duration of 5 minutes.

(iii) Measure the tank vent 

using a calibrated bag 

according to methods in 

§98.234(c) for a duration of 5 

minutes or until the bag is full, 

whichever is shorter. 

(iv) You may annually monitor 

leakage through compressor 

scrubber dump valve(s) into 

the tank using an acoustic leak 

detection device according to 

methods set forth in 

§98.234(a)(5).

Clarifying edits

25
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(k)(2) and 

(k)(2)(i)

(2) If the tank vapors from the 

vent stack are continuous for 

5 minutes, or the acoustic 

leak detection device detects 

a leak, then use one of the 

following two methods in 

paragraph (k)(2) of this 

section to quantify annual 

emissions:

(2) If the tank vapors from the 

vent stack are continuous for 5 

minutes, or the optical gas 

imaging instrument or acoustic 

leak detection device detects a 

leak, then you must use one of 

the methods in either 

paragraph (k)(2)(i) or (k)(2)(ii) 

of this section.

Clarifying edits; 

corrects references

(i) Use a meter, such as a 

turbine meter, calibrated bag, 

or high flow sampler to 

estimate tank vapor volumes 

from the vent stack according 

to methods set forth in 

§98.234(b) through (d)....If 

the vent is directly measured 

for five minutes under 

paragraph §98.233(k)(1) of 

this section to detect 

continuous leakage, this 

serves as the measurement.

(i) Use a flow meter, such as a 

turbine meter, calibrated bag, 

or high volume sampler to 

estimate tank vapor volumes 

from the vent stack according 

to methods set forth in 

§98.234(b) through (d)....If the 

vent is directly measured for 

five minutes under paragraph 

(k)(1)(ii) or (k)(1)(iii) of this 

section to detect continuous 

leakage, this serves as the 

measurement.

§98.233(k)(4) and 

(k)(4)(i)

(2)(iii) Use the appropriate 

gas composition in paragraph 

(u)(2)(iii) of this section.

(4) Use the requirements 

specified in paragraphs 

(k)(4)(i) and (k)(4)(ii) of this 

section to quantify annual 

emissions.

(i) Use the appropriate gas 

composition in paragraph 

(u)(2)(iii) of this section.

Renumbered to 

(k)(4)(i)

§98.233(k)(4)(ii) (2)(iv) Calculate GHG 

volumetric and mass 

emissions at standard 

conditions....

(4)(ii) Calculate CH4 and CO2

volumetric and mass emissions 

at standard conditions...

Clarifying edits, 

renumbered to 

(k)(4)(ii)

§98.233(k)(3) (3) If the leaking dump 

valve(s) is fixed following 

leak detection, the annual 

emissions shall be calculated 

from the beginning of the 

calendar year to the time the 

valve(s) is repaired.

(3) If a leaking dump valve is 

identified, the leak must be 

counted as having occurred 

since the beginning of the 

calendar year, or from the 

previous test that did not detect 

leaking in the same calendar 

year. If the leaking dump valve 

is fixed following leak 

detection, the leak duration 

will end upon being repaired. 

If a leaking dump valve is 

identified and not repaired, the 

leak must be counted as having 

occurred through the rest of the 

calendar year.

Clarifying edits, 

including what to do if 

an earlier test showed 

no leak, and how to 

determine end of leak 

duration

26
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(k)(5) (4) Calculate annual 

emissions from storage tanks 

to flares as follows:

(5) Calculate annual emissions 

from storage tanks to flares as 

specified in paragraphs 

(k)(5)(i) and (k)(5)(ii) of this 

section.

Corrects references 

and renumbers (k)(4) 

to (k)(5)

§98.233(l)(2) and 

§98.233(m)(2) 

(l)(2) ... according to one of 

the two procedures in 

paragraph (l)(2) of this 

section to determine GOR:

(l)(2) ... according to one of 

the procedures specified in 

paragraph (l)(2)(i) or (l)(2)(ii) 

of this section to determine 

GOR.

Clarifying edits

(m)(2) ...then use one of the 

two procedures in paragraph 

(m)(2) of this section to 

determine GOR:

(m)(2) ....then you must use 

one of the procedures specified 

in paragraphs (m)(2)(i) or 

(m)(2)(ii) of this section to 

determine GOR.

§98.233(l)(2)(ii) 

and 

§98.233(m)(2)(ii)

(ii) Or you may use an 

industry standard practice as 

described in §98.234(b).

(ii) You may use an industry 

standard practice as described 

in §98.234(b).

Applies active voice

§98.233(l)(3) (3) Estimate venting 

emissions using Equation W17A or Equation W-17B of 

this section.

(3) Estimate venting emissions 

using Equation W-17A (for oil 

wells) or Equation W-17B (for 

gas wells) of this section.

Clarifying edits

Terms “FR” and 

“D” of Equations 

W-17A and W-17B

FR = Flow rate in barrels of 

oil per day for the oil well(s) 

being tested.

...

D = Number of days during 

the year, the well(s) is tested.

FR = Average annual flow rate 

in barrels of oil per day for the 

oil well(s) being tested.

...

D = Number of days during the 

calendar year that the well(s) is 

tested.

Clarifying edits

§98.233(l)(5) (5) Calculate both CH4 and 

CO2 volumetric and mass 

emissions from volumetric 

natural gas emissions using 

calculations in paragraphs (u) 

and (v) of this section.

(5) Calculate both CH4 and 

CO2 volumetric and mass 

emissions from natural gas 

volumetric emissions using 

calculations in paragraphs (u) 

and (v) of this section.

Clarifying edit

27
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(l)(6) and 

§98.233(m)(5)

(l)(6) Calculate emissions 

from well testing to flares as 

follows:

(l)(6) Calculate emissions from 

well testing if emissions are 

routed to a flare as specified in 

paragraphs (l)(6)(i) and 

(l)(6)(ii) of this section.

Corrects references; 

§98.233(m)(6) is 

renumbered to (m)(5)

(i) Use the well testing 

emissions volume and gas 

composition as determined in 

paragraphs (l)(1) through (3) 

of this section.

(i) Use the well testing 

emissions volume and gas 

composition as determined in 

paragraphs (l)(1) through (4) of 

this section.

(m)(6) Calculate emissions 

from associated natural gas to 

flares as follows:

(m)(5) Calculate emissions 

from associated natural gas if 

emissions are routed to a flare 

as specified in paragraphs 

(m)(5)(i) and (m)(5)(ii) of this 

section.

(i) Use the associated natural 

gas volume and gas 

composition as determined in 

paragraph (m)(1) through (4) 

of this section.

(i) Use the associated natural 

gas volume and gas 

composition as determined in 

paragraph (m)(1) through 

(m)(4) of this section.

§98.233(m)(1) (1) ... If GOR from each well 

is not available, the GOR 

from a cluster of wells in the 

same sub-basin category shall 

be used.

(1) ... If GOR from each well is 

not available, use the GOR 

from a cluster of wells in the 

same sub-basin category.

Applies active voice

Term “Vp,q” of 

Equation W-18

Vp,q = Volume of oil 

produced, for well p in subbasin q, in barrels in the 

calendar year during which 

associated gas was vented or 

flared.

Vp,q = Volume of oil produced, 

for well p in sub-basin q, in 

barrels in the calendar year 

during time periods in which 

associated gas was vented or 

flared.

Clarifying edits

§98.233(n) (n) Flare stack emissions. 

Calculate CO2, CH4, and N2O 

emissions from a flare stack 

as follows:

(n) Flare stack emissions. 

Calculate CO2, CH4, and N2O 

emissions from a flare stack as 

specified in paragraphs (n)(1) 

through (n)(9) of this section.

Clarifying edits

§98.233(n)(1) (1) ...If you do not have a 

continuous flow measurement 

device on the flare, you can 

install a flow measuring 

device on the flare or use 

engineering calculations

based on process knowledge, 

company records, and best 

available data.

(1) ...If you do not have a 

continuous flow measurement 

device on the flare, you can use 

engineering calculations based 

on process knowledge, 

company records, and best 

available data.

Clarifying edit,

corrects typo

28
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(n)(2) (2) ... you must use the 

appropriate gas compositions 

for each stream of 

hydrocarbons going to the 

flare as follows:

(2) ... you must use the 

appropriate gas compositions 

for each stream of 

hydrocarbons going to the flare 

as specified in paragraphs 

(n)(2)(i) through (n)(2)(iii) of 

this section.

Clarifying edits

(i) For onshore natural gas 

production, determine natural 

gas composition using 

(u)(2)(i) of this section.

(i) For onshore natural gas 

production, determine the 

GHG mole fraction using 

paragraph (u)(2)(i) of this 

section.

(ii) For onshore natural gas 

processing, when the stream 

going to flare is natural gas, 

use the GHG mole percent in 

feed natural gas for all 

streams upstream of the demethanizer or dew point 

control, and GHG mole 

percent in facility specific 

residue gas to transmission 

pipeline systems for all 

emissions sources 

downstream of the demethanizer overhead or dew 

point control for onshore 

natural gas processing 

facilities. For onshore natural 

gas processing plants that 

solely fractionate a liquid 

stream, use the GHG mole 

percent in feed natural gas 

liquid for all streams.

(ii) For onshore natural gas 

processing, when the stream 

going to flare is natural gas, 

use the GHG mole fraction in 

feed natural gas for all streams 

upstream of the de-methanizer 

or dew point control, and GHG 

mole fraction in facility 

specific residue gas to 

transmission pipeline systems 

for all emissions sources 

downstream of the demethanizer overhead or dew 

point control for onshore 

natural gas processing 

facilities. For onshore natural 

gas processing plants that 

solely fractionate a liquid 

stream, use the GHG mole 

fraction in feed natural gas 

liquid for all streams.

§98.233(n)(2)(iii) (iii) For any applicable 

industry segment, ...

(iii) For any industry segment 

required to report flare stack 

emissions under §98.232, ...

Clarifying edits

Terms “Vs,”

“XCH4,” “XCO2,” and 

“Yj” of Equations 

W-19 and W-20

Va = Volume of gas sent to 

flare in cubic feet, during the 

year.

...

Vs = Volume of gas sent to 

flare in standard cubic feet, 

during the year as determined 

in paragraph (n)(1) of this 

section.

...

Specifies requirements 

for determining each 

parameter and clarifies 

that the volume of gas 

is to be at standard 

conditions.

XCH4 = Mole fraction of CH4

in gas to the flare.

XCH4 = Mole fraction of CH4 in 

the feed gas to the flare as 

determined in paragraph (n)(2) 

of this section.

29
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

XCO2 = Mole fraction of CO2

in gas to the flare....

XCO2 = Mole fraction of CO2 in 

the feed gas to the flare as 

determined in paragraph (n)(2) 

of this section.

Yj = Mole fraction of gas 

hydrocarbon constituents j 

(such as methane, ethane, 

propane, butane, and 

pentanes-plus).

...Yj = Mole fraction of 

hydrocarbon constituents j 

(such as methane, ethane, 

propane, butane, and pentanesplus) in the feed gas to the flare 

as determined in paragraph 

(n)(1) of this section.

N/A (n)(7) [Reserved] None Removes reserved 

requirements and

renumbers following 

paragraphs

§98.233(n)(8) (9) If you operate and 

maintain a CEMS that has 

both a CO2 concentration 

monitor and volumetric flow 

rate monitor, you must 

calculate only CO2 emissions 

for the flare. ... If a CEMS is 

used to calculate flare stack 

emissions, the requirements 

specified in paragraphs (n)(1) 

through (n)(7) are not 

required. If a CO2

concentration monitor and 

volumetric flow rate monitor 

are not available, you may 

elect to install a CO2

concentration monitor and a 

volumetric flow rate monitor 

that comply with all of the 

requirements specified for the 

Tier 4 Calculation 

Methodology in subpart C of 

this part (General Stationary 

Fuel Combustion).

(8) If you operate and maintain 

a CEMS that has both a CO2

concentration monitor and 

volumetric flow rate monitor 

for the combustion gases from 

the flare, you must calculate 

only CO2 emissions for the 

flare. ...If a CEMS is used to 

calculate flare stack emissions, 

the requirements specified in 

paragraphs (n)(1) through 

(n)(7) are not required.

Renumbers paragraph 

and removes 

redundant text

§98.233(q) Leak detection and leaker 

emission factors. You must 

use the methods described in 

§98.234(a) to conduct leak 

detection(s) of equipment 

leaks from all component 

types listed in §98.232(d)(7), 

(e)(7), (f)(5), (g)(3), (h)(4), 

and (i)(1). This paragraph (q) 

applies to component types in 

streams with gas content 

Equipment leak surveys. You 

must use the methods 

described in §98.234(a) to 

conduct leak detection(s) of 

equipment leaks from all 

component types listed in 

§98.232(d)(7), (e)(7), (f)(5), 

(g)(3), (h)(4), and (i)(1). This 

paragraph (q) applies to 

component types in streams 

with gas content greater than 

Makes terminology 

consistent with 

corresponding 

reporting section 

(§98.236(q)); 

clarifying edits

30
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

greater than 10 percent CH4

plus CO2 by weight. 

Component types in streams 

with gas content less than 10 

percent CH4 plus CO2 by 

weight do not need to be 

reported. Tubing systems 

equal to or less than one half 

inch diameter are exempt 

from the requirements of this 

paragraph (q) and do not need 

to be reported. If equipment 

leaks are detected for sources 

listed in this paragraph (q), 

calculate equipment leak 

emissions per component type 

per reporting facility using 

Equations W-30A or W-30B 

of this section for each 

component type. Use 

Equation W-30A for industry 

segments listed in 

98.230(a)(3)-(a)(7). Use 

Equation W-30B for industry 

segments in 98.230(a)(8).

10 percent CH4 plus CO2 by 

weight. Component types 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. For industry 

segments listed in 

§98.230(a)(3) through (a)(8), if 

equipment leaks are detected 

for component types listed in 

this paragraph (q), then you 

must calculate equipment leak 

emissions per component type 

per reporting facility using 

Equation W-30 of this section. 

For the industry segment listed 

in §98.230(a)(8), the results 

from Equation W-30 are used 

to calculate population 

emission factors on a 

meter/regulator run basis using 

Equation W-31 of this section.

If you chose to conduct 

equipment leak surveys at all 

above grade transmission 

distribution transfer stations 

over multiple years, “n,”

according to paragraph 

(q)(8)(i) of this section, then 

you must calculate the 

emissions from all above grade 

transmission-distribution 

transfer stations as specified in 

paragraph (q)(9) of this 

section.

Term “Tp,z” in 

Equation W-30

The total time the surveyed 

component “z,” component 

type “p” was found leaking 

and operational, in hours. ...

The total time the surveyed 

component “z,” component 

type “p,” was assumed to be 

leaking and operational, in 

hours. ...

Clarifying edit

31
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(q)(1) You must select to conduct 

either one leak detection 

survey in a calendar year or 

multiple complete leak 

detection surveys in a 

calendar year. The number of 

leak detection surveys 

selected must be conducted 

during the calendar year.

You must conduct either one 

leak detection survey in a 

calendar year or multiple 

complete leak detection 

surveys in a calendar year. The 

leak detection surveys selected 

must be conducted during the 

calendar year.

Grammatical 

corrections

§98.233(q)(3) and 

(q)(4)

... facilities shall use the 

appropriate default leaker 

emission factors listed in 

Table ... of this subpart for 

equipment leaks detected 

from valves, connectors, open 

ended lines, pressure relief 

valves, and meters.

... facilities must use the 

appropriate default total 

hydrocarbon leaker emission 

factors for compressor 

components in gas service and 

non-compressor components in 

gas service listed in Table ... 

of this subpart.

Clarifying edits

§98.233(q)(5) and 

(r)(3)

(q)(5) Underground natural 

gas storage facilities for 

storage stations shall use the 

appropriate default leaker 

emission factors listed in 

Table W-4 of this subpart for 

equipment leaks detected 

from valves, connectors, open 

ended lines, pressure relief 

valves, and meters.

(q)(5) Underground natural gas 

storage facilities must use the 

appropriate default total 

hydrocarbon leaker emission 

factors for storage stations in 

gas service listed in Table W-4 

of this subpart.

Clarifying edits

(r)(3) Underground natural 

gas storage facilities for 

storage wellheads shall use 

the appropriate default 

population emission factors 

listed in Table W-4 of this 

subpart for equipment leak 

from connectors, valves, 

pressure relief valves, and 

open ended lines.

(r)(3) Underground natural gas 

storage facilities must use the 

appropriate default total 

hydrocarbon population 

emission factors for storage 

wellheads in gas service listed 

in Table W-4 of this subpart.

§98.233(q)(6) and 

(r)(4)

(q)(6) ... shall use the 

appropriate default leaker 

emission factors listed in 

Table W-5 of this subpart for 

equipment leaks detected 

from valves, pump seals, 

connectors, and other.

(q)(6) ... must use the 

appropriate default methane 

leaker emission factors for 

LNG storage components in 

gas service listed in Table W-5 

of this subpart.

Clarifying edits

32
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

(r)(4) ... shall use the 

appropriate default population 

emission factors listed in 

Table W-5 of this subpart for 

equipment leak from vapor 

recovery compressors.

(r)(4) ... must use the 

appropriate default methane 

population emission factor for 

LNG storage compressors in 

gas service listed in Table W-5 

of this subpart.

§98.233(q)(7) and 

(r)(5)

(q)(7) ... shall use the 

appropriate default leaker 

emission factors listed in 

Table W-6 of this subpart for 

equipment leaks detected 

from valves, pump seals, 

connectors, and other.

(q)(7) ... must use the 

appropriate default methane 

leaker emission factors for 

LNG terminals components in 

LNG service listed in Table 

W-6 of this subpart.

Clarifying edits

(r)(5) ... shall use the 

appropriate default population 

emission factor listed in Table 

W-6 of this subpart for 

equipment leak from vapor 

recovery compressors.

(r)(5) ... must use the 

appropriate default methane 

population emission factor for 

LNG terminal compressors in 

gas service listed in Table W-6 

of this subpart.

§98.233(q)(8) Natural gas distribution 

facilities for above grade 

transmission-distribution 

transfer stations, shall use the 

appropriate default leaker 

emission factors listed in 

Table W-7 of this subpart for 

equipment leaks detected 

from connectors, block 

valves, control valves, 

pressure relief valves, orifice 

meters, regulators, and open 

ended lines. Leak detection at 

natural gas distribution 

facilities is only required at 

above grade stations that 

qualify as transmissiondistribution transfer stations. 

Below grade transmissiondistribution transfer stations 

and all metering-regulating 

stations that do meet the 

definition of transmissiondistribution transfer stations 

are not required to perform 

component leak detection 

under this section.

Natural gas distribution 

facilities must use Equation W30 of this section and the 

default methane leaker 

emission factors for 

transmission-distribution 

transfer station components in 

gas service listed in Table W-7 

of this subpart to calculate 

component emissions from 

annual equipment leak surveys 

conducted at above grade 

transmission-distribution 

transfer stations. Natural gas 

distribution facilities are 

required to perform equipment 

leak surveys only at above 

grade stations that qualify as 

transmission-distribution 

transfer stations. Below grade 

transmission-distribution 

transfer stations and all 

metering-regulating stations 

that do not meet the definition 

of transmission-distribution 

transfer stations are not 

required to perform equipment 

leak surveys under this section.

Clarifying edits; 

grammatical 

correction

33
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(q)(8)(i) Natural gas distribution 

facilities may choose to 

conduct leak detection at the 

T-D transfer stations over 

multiple years, not exceeding 

a five year period to cover all 

T-D transfer stations. If the 

facility chooses to use the 

multiple year option then the 

number of T-D transfer 

stations that are monitored in 

each year should be 

approximately equal across 

all years in the cycle without 

monitoring the same station 

twice during the multiple year 

survey.

Natural gas distribution 

facilities may choose to 

conduct equipment leak 

surveys at all above grade 

transmission-distribution 

transfer stations over multiple 

years “n,” not exceeding a five 

year period to cover all above 

grade transmission-distribution 

transfer stations. If the facility 

chooses to use the multiple 

year option then the number of 

transmission-distribution 

transfer stations that are 

monitored in each year should 

be approximately equal across 

all years in the cycle.

Clarifying edits

§98.233(r) Population count and 

emission factors. This 

paragraph applies to 

emissions sources listed in 

§98.232 (c)(21), (f)(5), (g)(3), 

(h)(4), (i)(2), (i)(3), (i)(4), 

(i)(5), and (i)(6) on streams 

with gas content greater than 

10 percent CH4 plus CO2 by 

weight. Emissions sources in 

streams with gas content less 

than 10 percent CH4 plus CO2

by weight do not need to be 

reported. Tubing systems 

equal to or less than one half 

inch diameter are exempt 

from the requirements of 

paragraph (r) of this section 

and do not need to be 

reported. Calculate emissions 

from all sources listed in this 

paragraph using Equation W31 of this section.

Equipment leaks by population 

count. This paragraph applies 

to emissions sources listed in 

§98.232 (c)(21), (f)(5), (g)(3), 

(h)(4), (i)(2), (i)(3), (i)(4), 

(i)(5), and (i)(6) on streams 

with gas content greater than 

10 percent CH4 plus CO2 by 

weight. Emissions sources 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 (r) and do not need 

to be reported. Tubing systems 

equal to or less than one half 

inch diameter are exempt from 

the requirements of paragraph 

(r) of this section and do not 

need to be reported. You must 

calculate emissions from all 

emission sources listed in this 

paragraph using Equation W32A of this section, except for 

natural gas distribution facility 

emission sources listed in 

§98.232 (i)(3). Natural gas 

distribution facility emission 

sources listed in §98.232 (i)(3) 

must calculate emissions using 

Equation W-32B and 

according to paragraph 

(r)(6)(ii) of this section. 

Makes terminology 

consistent with 

corresponding 

reporting section 

(§98.236(r)); 

clarifying edits

34
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(r) 

Equations

Eq. W-31 Eq. W-32A and Eq. W-32B Renumbered; 

harmonizing change 

with edits to 

§98.233(q)

§98.233(r)(2) Onshore petroleum and 

natural gas production 

facilities shall use the 

appropriate default population 

emission factors listed in 

Table W-1A of this subpart 

for equipment leaks from 

valves, connectors, open 

ended lines, pressure relief 

valves, pump, flanges, and 

other. Major... 

Onshore petroleum and natural 

gas production facilities must 

use the appropriate default 

whole gas population emission 

factors listed in Table W-1A of 

this subpart. Major... 

Clarifying edit

§98.233(r)(6) ... shall use the appropriate 

emission factors as described 

in paragraph (r)(6) of this 

section.

... must use the appropriate 

methane emission factors as 

described in paragraphs

(r)(6)(i) and (r)(6)(ii) of this 

section.

Clarifying edits

§98.233(r)(6)(i) ... shall use the appropriate 

default population emission 

factors listed in Table W-7 of 

this subpart. Below grade T-D 

transfer stations shall use the 

emission factor for below 

grade metering-regulating 

stations.

... must use the appropriate 

default methane population 

emission factors listed in Table 

W-7 of this subpart. Below 

grade transmission-distribution 

transfer stations must use the 

emission factor for below 

grade metering-regulating 

stations.

Clarifying edits

35
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(r)(6)(ii) Emissions from all above 

grade metering-regulating 

stations (including above 

grade TD transfer stations) 

shall be calculated by 

applying the emission factor 

calculated in Equation W-32 

and the total count of 

meter/regulator runs at all 

above grade meteringregulating stations (inclusive 

of TD transfer stations) to 

Equation W-31. The facility 

wide emission factor in 

Equation W-32 will be 

calculated by using the total 

volumetric GHG emissions at 

standard conditions for all 

equipment leak sources 

calculated in Equation W-30B 

in paragraph (q)(8) of this 

section and the count of 

meter/regulator runs located 

at above grade transmissiondistribution transfer stations 

that were monitored over the 

years that constitute one 

complete cycle as per 

paragraph (q)(8)(i) of this 

section. A meter on a 

regulator run is considered 

one meter/regulator run. 

Reporters that do not have 

above grade T-D transfer 

stations shall report a count of 

above grade meteringregulating stations only and 

do not have to comply with 

§98.236(c)(16)(xix).

Above grade meteringregulating stations that are not 

above grade transmissiondistribution transfer stations 

must use the meter/regulator 

run population emission factor 

calculated in Equation W-31. 

Natural gas distribution 

facilities that do not have 

above grade transmissiondistribution transfer stations 

are not required to calculate 

emissions for above grade 

metering-regulating stations

and are not required to report 

GHG emissions in 

§98.236(r)(2)(v).

Harmonizing edits 

with changes to 

§98.233(q)

§98.233(s)(2) Offshore production facilities 

that are not under BOEMRE 

jurisdiction shall use 

monitoring methods and 

calculation methodologies 

published by BOEMRE 

referenced in 30 CFR 250.302 

through 304 to calculate and 

report emissions (GOADS).

Offshore production facilities 

that are not under BOEMRE 

jurisdiction shall use the most 

recent monitoring methods and 

calculation methods published 

by BOEMRE referenced in 30 

CFR 250.302 through 304 to 

calculate and report annual 

emissions (GOADS).

Clarifying edits

36
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(s)(2)(i) For any calendar year that 

does not overlap with the 

most recent BOEMRE 

emissions study publication, 

report the most recent 

reported emissions data with 

emissions adjusted...

For any calendar year that does 

not overlap with the most 

recent BOEMRE emissions 

study publication, you may 

report the most recently 

reported emissions data 

submitted to demonstrate 

compliance with this subpart of 

part 98, with emissions 

adjusted ...

Clarifying edits

§98.233(s)(3) ... shall once in every 4 years 

use the most recent BOEMRE 

data collection and emissions 

estimation methods to report 

emission from the facility 

sources.

... shall once in every 4 years 

use the most recent BOEMRE 

data collection and emissions 

estimation methods to estimate 

emissions. These emission 

estimates would be used to 

report emissions from the 

facility sources as required in 

paragraph (1)(i) of this section.

Clarifying edits

§98.233(s)(4) ... shall use the most recent 

BOEMRE data collection and 

emissions estimation methods 

published by BOEMRE 

referenced in 30 CFR 250.302 

through 304 to calculate and 

report emissions (GOADS) to 

report emissions.

... must use the most recent 

BOEMRE data collection and 

emissions estimation methods 

published by BOEMRE 

referenced in 30 CFR 250.302 

through 304 to calculate and 

report emissions.

Applies active 

language and corrects

typographical error

§98.233(t) (t) Volumetric emissions. ... (t) GHG Volumetric emissions 

using actual conditions. ...

Clarifying edits

§98.233(u) (u) GHG volumetric 

emissions. Calculate GHG 

volumetric emissions at 

standard conditions as 

specified in paragraphs (u)(1) 

and (2) of this section, with 

mole fraction of GHGs in the 

natural gas determined by 

engineering estimate based on 

best available data unless 

otherwise specified.

(u) GHG volumetric emissions 

at standard conditions. 

Calculate GHG volumetric 

emissions at standard 

conditions as specified in 

paragraphs (u)(1) and (2) of 

this section. 

Clarifying edits

§98.233(u)(2)(iii), 

(u)(2)(iv), (u)(2)(v), 

(u)(2)(vi), and 

(u)(2)(vii)

... You may use a default 

95 percent methane and 

1 percent carbon dioxide 

fraction for GHG mole 

fraction in natural gas.

... You may use either a 

default 95 percent methane and 

1 percent carbon dioxide 

fraction for GHG mole fraction 

in natural gas or site specific 

engineering estimates based on 

best available data.

Clarifying edits

Term “Pi” of 

Equation W-36

Pi ρi Corrects typo (to 

Greek letter)

37
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.233(w) (w) ... Calculate CO2 pump 

blowdown emissions as 

follows:

(w) ... Calculate CO2 pump 

blowdown emissions from 

each EOR injection pump 

system as follows:

Clarifying edits

(1) Calculate the total volume 

in cubic feet ...

(1) Calculate the total injection 

pump system volume in cubic 

feet ...

(3) Calculate the total annual 

venting emissions using 

Equation W-37 of this 

section:

(3) Calculate the total annual 

CO2 emissions from each EOR 

injection pump system using 

Equation W-37 of this section:

Terms “MassCO2,”

“N,” and “Vv” of 

Equation W-37

MassCO2 = Annual EOR 

injection gas venting 

emissions in metric tons from 

blowdowns.

MassCO2 = Annual EOR 

injection pump system 

emissions in metric tons from 

blowdowns.

Clarifies terminology

N = Number of blowdowns 

for the equipment in the 

calendar year.

N = Number of blowdowns for 

the EOR injection pump 

system in the calendar year.

Vv = Total volume in cubic 

feet of blowdown equipment 

chambers (including 

pipelines, manifolds and 

vessels) between isolation 

valves.

Vv = Total volume in cubic 

feet of EOR injection pump 

system chambers (including 

pipelines, manifolds and 

vessels) between isolation 

valves.

§98.233(x), (x)(1), 

and term “Shl” of 

Equation W-38

(x) ... Calculate dissolved 

CO2 in hydrocarbon liquids 

produced through EOR 

operations as follows:

(x) ... Calculate CO2 emissions 

downstream of the storage tank 

from dissolved CO2 in 

hydrocarbon liquids produced 

through EOR operations as 

follows:

Clarifying edits

(1) ... Annual samples must 

be taken according to 

methods set forth in 

§98.234(b)...

(1) ... Annual samples of 

hydrocarbon liquids 

downstream of the storage tank 

must be taken according to 

methods set forth in §98.234(b) 

...

(2)...

Shl = Amount of CO2 retained 

in hydrocarbon liquids in 

metric tons per barrel, under 

standard conditions.

(2)...

Shl = Amount of CO2 retained 

in hydrocarbon liquids 

downstream of the storage 

tank, in metric tons per barrel, 

under standard conditions.

§98.233(z)(1)(i) and 

(ii)

All part 98 rule references in 

paragraphs (i) and (ii)

Added § symbol (e.g., “for that 

tier listed in §98.33”)

Corrects typographical 

error and rule citation 

error (ii) ...requirements specified 

in 98.236(c)(19) and not...

(ii) ...requirements specified in 

§98.236(z) and not...

38
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

Term “Va” of 

Equations W-39A 

and W-39B

Va = Volume of gas sent to 

combustion unit in cubic feet, 

during the year.

Va = Volume of gas sent to 

combustion unit in actual cubic 

feet, during the year.

Clarifying edit

Terms “YCO2,” “Yj”

and “YCH4” of 

Equations W-39A 

and W-39B

Concentration of... Mole fraction of... Clarifying edit

Term “HHV” of 

Equation W-40

HHV = For the higher heating 

value for field gas or process 

vent gas, use 1.235 × 10−3

mmBtu/scf for HHV.

HHV = Higher heating value 

of fuel, mmBtu/unit of fuel (in 

units consistent with the fuel 

quantity combusted). For the 

higher heating value for field 

gas or process vent gas, you 

may use either a default higher 

heating value of 1.235 × 10−3

mmBtu/scf for HHV or a sitespecific higher heating value. 

For natural gas that is not of 

pipeline quality or that has a 

high heat value less than 950 

Btu per standard cubic foot, 

use a site-specific higher 

heating value.

Clarifying edit

§98.234(a) You must use any of the 

methods described as follows 

in this paragraph to conduct 

leak detection(s) of 

equipment leaks and throughvalve leakage from all source 

types listed in §98.233(k), (o), 

(p) and (q) that occur during a 

calendar year, except as 

provided in paragraph (a)(4) 

of this section.

You must use any of the 

methods described as follows 

in this paragraph to conduct 

leak detection(s) of equipment 

leaks and through-valve 

leakage from all source types 

listed in §98.233(k), (o), (p) 

and (q) that occur during a 

calendar year.

Corrects reference 

error

§98.234(d)(1) (1) A technician following 

manufacturer instructions 

shall conduct measurements, 

including equipment 

manufacturer operating 

procedures and measurement 

methodologies relevant to 

using a high volume 

sampler...

(1) A technician following 

manufacturer instructions shall 

conduct measurements, 

including equipment 

manufacturer operating 

procedures and measurement 

methods relevant to using a 

high volume sampler...

Harmonizing edit

39
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.234(h) [Reserved] (h) For well venting for liquids 

unloading, if a monitoring 

period other than the full 

calendar year is used to 

determine the cumulative 

amount of time in hours of 

venting for each well (the term 

“Tp” in Equation W-7a and W7b of §98.233) or the number 

of unloading events per well 

(the term “Vp” in Equations W8 and W-9 of §98.233), then 

the monitoring period must 

begin before February 1 of the 

reporting year and must not 

end before December 1 of the 

reporting year. The end of one 

monitoring period must 

immediately precede the start 

of the next monitoring period 

for the next reporting year. All 

production days must be 

monitored and all venting 

accounted for.

Harmonizing edit with 

changes to §98.233(f). 

§98.238 Component means each metal 

to metal joint or seal of nonwelded connection separated 

by a compression gasket, 

screwed thread (with or 

without thread sealing 

compound), metal to metal 

compression, or fluid barrier 

through which natural gas or 

liquid can escape to the 

atmosphere.

Equipment leak means those 

emissions which could not 

reasonably pass through a 

stack, chimney, vent, or other 

functionally-equivalent 

opening.

Equipment leak detection

means the process of 

identifying emissions from 

equipment, components, and

other point sources.

None (these definitions 

removed in amendments)

Harmonizing edits 

with changes to 

§98.233(q) and (r)

40
Table 1. Minor Technical Corrections (continued)

Final Rule 

Citation Current Text Revised Text Reason for Change

§98.238 Meter/regulator run means a 

series of components used in 

regulating pressure or 

metering natural gas flow or 

both.

Meter/regulator run means a 

series of components used in 

regulating pressure or metering 

natural gas flow, or both, in the 

natural gas distribution 

industry segment. At least one 

meter, at least one regulator, or 

any combination of both on a 

single run of piping is 

considered one meter/regulator 

run.

Grammatical 

revisions; harmonizing 

edits

Sub-basin category, for 

onshore natural gas 

production, means ... Oil, 

high permeability gas, shale 

gas, coal seam, or other tight 

reservoir rock... Wells that 

produce from high 

permeability gas, shale gas, 

coal seam, or other tight 

reservoir rock are considered 

gas wells ... All wells that 

produce hydrocarbon liquids 

and do not meet the definition 

of a gas well in this sub-basin 

category definition are 

considered to be in the oil 

formation. All emission 

sources that handle 

condensate from gas wells in 

high permeability gas, shale 

gas, or tight reservoir rock 

formations are considered to 

be in the formation that the 

gas well belongs to and not in 

the oil formation.

Sub-basin category, for 

onshore natural gas production,

means ...Oil, high 

permeability gas, shale gas, 

coal seam, or other tight gas 

reservoir rock... Wells that 

produce only from high 

permeability gas, shale gas, 

coal seam, or other tight gas 

reservoir rock are considered 

gas wells ... All wells that 

produce hydrocarbon liquids 

(with or without gas) and do 

not meet the definition of a gas 

well in this sub-basin category 

definition are considered to be 

in the oil formation. All 

emission sources that handle 

condensate from gas wells in 

high permeability gas, shale 

gas, or tight gas reservoir rock 

formations are considered to be 

in the formation that the gas 

well belongs to and not in the 

oil formation.

41