Mandatory Reporting of Greenhouse Gases: 

Petroleum and Natural Gas Systems 

1 of 206 

 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

WASHINGTON, D.C. 20460 

OFFICE OF 

 AIR AND RADIATION 

40 CFR Part 98 Subpart W Rule Redline 

This document shows the following proposed amendments: 

1. 2011 Proposed Technical Corrections to Provisions in 

Subpart W: Amendments shown with no highlighting. 

Comments on proposed technical correction must be 

submitted according to the instructions in the 

preamble to that rule. See 76 FR 47392. 

2. 2011 Proposed Technical Revisions to Provisions in 

Subpart W: Amendments shown with yellow highlighting. 

Comments on proposed technical revisions must be 

submitted according to the instructions in the 

preamble to that rule. 

3. 2011 Proposed Amendments to Provisions Related to Best 

Available Monitoring Methods: Amendments shown with 

green highlighting. Comments on proposed amendments 

to provisions related to best available monitoring 

methods were to be submitted according to the 

instructions in the preamble to that rule. See 76 FR 

37300.

Mandatory Reporting of Greenhouse Gases: Technical 

Revisions to the Electronics Manufacturing and the 

Petroleum and Natural Gas Systems Categories of the 

Greenhouse Gas Reporting Rule. Docket: EPA-HQ-OAR-2011-0512

DRAFT -- This draft only contains redline/strikeout 

text. This document is provided solely for 

informational purposes. It does not provide legal 

advice, have legally binding effect, or expressly or 

implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or 

benefits in regard to any person. The purpose of this 

redline is to facilitate public review of the 2011 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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For the reasons stated in the preamble, title 40, 

chapter I, of the Code of Federal Regulations is amended as 

follows: 

PART 98–[AMENDED][AMENDED]

1. The authority citation for part 98 continues to 

read as follows: 

Authority: 42 U.S.C. 7401-7671q. 

Subpart A—[Amended]General Provision[AMENDED]

2. Section 98.1 is amended by adding paragraph (c) to 

read as follows:

§98.1 Purpose and scope.

 (a) This part establishes mandatory greenhouse gas 

(GHG) reporting requirments for owners and operators of 

certain facilities that directly emit GHG as well as for 

certain suppliers. For suppliers, the GHGs reported are the 

quantity that would be emitted from combustion or use of 

the products supplied. 

 (b) Owners and operators of facilities and suppliers 

that are subject to this part must follow the requirements 

of this subpart and all applicable subparts of this part. 

If a conflict exists between a provision in subpart A and 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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any other applicable subpart, the requirements of the 

applicable subpart shall take precedence. 

 (c) For facilities required to report under onshore 

petroleum and natural gas production under subpart W of 

this part, the terms Owner and Operator used in subpart A 

have the same definitions as Onshore petroleum and natural 

gas production owner or operator, as defined in §98.238 of 

this part.

2. Section 98.2 is amended by revising the 

introductory text to paragraph (a) to read as follows: 

§98.2 Who must report?

(a) The GHG reporting requirements and related 

monitoring, recordkeeping, and reporting requirements of 

this part apply to the owners and operators of any facility 

that is located in the United States or under or attached 

to the Outer Continental Shelf (as defined in 43 U.S.C. 

1331) and that meets the requirements of either paragraph 

(a)(1), (a)(2), or (a)(3) of this section; and any supplier 

that meets the requirements of paragraph (a)(4) of this 

section: 

(d) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2 per year threshold for importerts and 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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exporters of coal-to-liquid products under paragraph (a)(4) 

of this section, calculate the mass in metric tons per year 

of CO2 that would result from the complete combustion or 

oxidation of the quantity of the quantity of coal-to-liquid 

products that are imported during the reporting year and, 

that exported during the reporting year. Compare the 

imported quantities and exported quantities separately to 

the 25,000 metric ton CO2 per year threshold. Calculate the 

quantities using the methodologuy specified in subpart LL 

of this part. 

(e) To calculate GHG quanitities for comparison to the 

25,000 metric ton CO2e per year threshold for impoerters and 

exporters of pretroleum products under paragraph (a)(4)(ii) 

of this section, calculate the mass in metric tons per year 

of CO2 that would result from the complete combustion or 

oxidation of the combined volume of petroleum products and 

natural gas liquids that are imported during the reporting 

year and that are exported during the reporting year. 

Compare the imported quantities and the exported quantities 

separately to the 25,000 metric ton CO2 per year threshold. 

Calculate quantities using the methodology specified in 

subpart MM of this part. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(f) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2e per year threshold under paragraph 

(a)(4) of this section for importers and exporters of 

industrial greenhouse gases and for importers and exporters 

of CO2, the owner or operator shall calculate the mass in 

metric tons per year of CO2e imports and exports as 

described in paragraphs (f)(1) through (f)(3) of this 

section. Compare the imported quantities and the exported 

quantities separately to the 25,000 metric ton CO2 per year 

threshold. 

(h) An owner or operator of a facility or supplier 

that does not meet the applicability requirements of 

paragraph (a) of this section is not subject to this rule. 

Such owner or operator would become subject to the rule and 

reporting requirements, if a facility or supplier exceeds 

the applicability requirments of paragraph (a) of this 

section at a later time pursuant to §98.3(b)(3). Thus, the 

owner or operator should reevaluate the applicability to 

this part (including the revisisng of any relevant 

emissions caclulations or other calculations) whenever 

there is any change that could casuse a facility or 

supplier to meet the applicability requirements of 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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paragraph (a) of this section. Such changes include but are 

not limited to process modifications, increases in 

operating hours, increases in production, changes in fuel 

or raw material use, addition of equipment, and facility 

expansion. 

(i)

(3) If the operations of a facility or supplier are 

changed such that all applicable GHG-emitting processes and 

operations listed in paragraphs (a)(1) through (a)(4) of 

this section cease to operate, then the owner or operator 

is exempt from reporting in the years following the year in 

which cessation of such operations occurs, provided that 

the owner or operator submits a notification to the 

Administrator that announces the cessation of reporting and 

certifies to the closure of all GHG-emitting processes and 

operations no later than March 31 of the year following such 

changes. This paragraph (i)(3) does not apply to seasonal 

or other temporary cessation of operations. This parargraph 

(i)(3) does not apply to facilities with municipal solid 

waster landfills or industrial waste land fills, or to 

underground coal mines. The owner or operator must resume 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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reporting for any future calendar year during which any of 

the GHG-emitting processes or operations resume operation. 

* * * * * 

§98.3 What are the general monitoring, reporting, 

recordkeeping and verification requirements of this part?

 (b) Schedule. The annual GHG report for reporting year 

2010 must be submitted no later than September 30, 2011. 

The annual report for reporting years 2011 and beyond must 

be submitted no later than March 31 of each calendar year 

for GHG emissions in the previous calendar year, except as 

provided in paragraph (b)(1) of this section. 

 (1) For reporting year 2011, GHG information required 

by the subparts listed in paragraphs (b)(1)(i) through 

(b)(1)(xii) of this section must be submitted no later than 

September 28, 2012. This reporting date applies only to the 

data reporting requirements indentified in the listed 

subparts and does not affect data reporting requirements of 

other subparts that apply to a facility or supplier.

 (i) Electronics Manufacturing (subpart I).

 (ii) Fluorinated Gas Production (subpart L).
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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 (iii) Magnesium Production (subpart T).

 (iv) Petroleum and Natural Gas Systems (subpart W).

 (v) Use of Electronic Transmission and Distribution 

Equipment (subpart DD).

 (vi) Underground Coal Mines (subpart FF).

 (vii) Industrial Wastewater Treatment (subpart II).

 (viii) Imports and Exports of Equipment Pre-charged 

with Fluorinated GHGs or Containing Fluorinated GHGs in 

Closed-cell Foams (subpart QQ).

 (ix) Geologic Sequestration of Carbon Dioxide (subpart 

RR).

 (x) Manufacture of Electric Transmission and 

Distribution (subpart SS). 

 (xi) Industrial Waste Landfills (subpart TT). 

 (xii) Injection of Carbon Dioxide (subpart UU). 

 (4) Unless otherwise stated, if the final day of any 

time period falls on a weekend or a Federal holiday, the 

time shall be extended to the next business day.

 (c) Content of the annual report.

 (5)
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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 (ii) Quantity of each GHG from each applicable supply 

category in Table A-5 of this subpart, expressed in metric 

tons of each GHG. For fluorinated GHG, report quantities of 

all fluorinated GHG, including those not listed in Table A1 of this subpart.

 (7) A brief description of each “best available 

monitoring method” used, the parameter measured using the 

method, and the time period during which the “best 

available monitoring method” was used, if applicable. 

 (10) NAICS code(s) that apply to the facility or 

supplier. 

 (i) Primary NAICS code. Report the NAICS code that 

most accurately describes the facility or supplier’s 

primary product/activity/service. This primary 

product/activity/service is the principal source of revenue 

for the facility or supplier. A facility or supplier that 

has two distinct products/activities/services providing 

comparable revenue may report a second primary NAICS code.

 (ii) Additional NAICS code(s). Report all additional 

NAICS codes that describe all 

product(s)/activity(s)/service(s) at the facility or 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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supplier that are not related to the principal source of 

revenue. 

 (11) Legal name(s) and physical address(es) of the 

highest-level United States parent company(s) of the owners 

(or operators) of the facility or supplier and the 

percentage of ownership interest for each listed parent 

company as of December 31 of the year for which data are 

being reported according to the following instructions:

 (i) If the facility or supplier is entirely owned by a 

single United States company that is not owned by another 

company, provide that company’s legal name and physical 

address as the United States parent company and report 100 

percent ownership.

 (ii)If the facility or supplier is entirely owned by a 

single United States company that is, itself, owned by a 

another company (e.g., it is a division or subsidiary of a 

higher-level company), provide the legal name and physical 

address of the highest-level company in the ownership 

hierarchy as the United States parent company and report 

100 percent ownership. 

 (iii) If the facility or supplier is owned by more 

than one United States company (e.g., company A owns 40 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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percent, company B owns 35 percent, and company C owns 25 

percent), provide the legal names and physical addresses of 

all the highest-level companies with an ownership interest 

as the United States parent companies, and report the 

percent ownership of each company.

 (iv) If the facility or supplier is owned by a joint 

venture or a cooperative, the joint venture or cooperative 

is its own United States parent company. Provide the legal 

name and physical address of the joint venture or 

cooperative as the United States parent company, and report 

100 percent ownership by the joint venture or cooperative.

 (v) If the facility or supplier is entirely owned by a 

foreign company, provide the legal name and physical 

address of the foreign company’s highest-level company 

based in the United States as the United States parent 

company, and report 100 percent ownership. 

 (vii) If the facility or supplier is a federally owned 

facility, report “U.S. Government” and do not report 

physical address or percent ownership. 

 (g) Recordkeeping. An owner or operator that is 

required to report GHGs under this part must keep records 

as specified in this paragraph. Retain all required records 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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for at least 3 years from the date of submission of the 

annual GHG report for the reporting year in which the 

record was generated. The records shall be kept in an 

electronic or hard-copy format (as appropriate) and 

recorded in a form that is suitable for expeditious 

inspection and review. Upon request by the Administrator, 

the records required under this section must be made 

available to EPA. Records may be retained off site if the 

records are readily available for expeditious inspection 

and review. For records that are electronically generated 

or maintained, the equipment or software necessary to read 

the records shall be made available, or, if requested by 

EPA, electronic records shall be converted to paper 

documents. You must retain the following records, in 

addition to those records prescribed in each applicable 

subpart of this part:

3. Section 98.6 is amended by adding the following 

definitions in alphabetical order and revising the 

definition of “United States” to read as follows:
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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3. Section 98.6 is amended by revising the definitions 

for “Continuous bleed” and “Intermittent bleed pneumatic 

devices” to read as follows:

§98.6 Definitions.

 All the terms used in this part shall have the same 

meaning given in the Clean Air Act and in this section.

Absorbent circulation pump means a pump commonly 

powered by natural gas pressure that circulates the 

absorbent liquid between the absorbent regenerator and 

natural gas contactor. 

* * * * * 

Air injected flare means a flare in which air is blown 

into the base of a flare stack to induce complete 

combustion of gas. 

* * * * * 

Blowdown vent stack emissions mean natural gas and/or 

CO2 released due to maintenance and/or blowdown operations 

including compressor blowdown and emergency shut-down (ESD) 

system testing. Emissions from emergency events are not 

eincluded.

* * * * * 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Calibrated bag means a flexible, non-elastic, antistatic bag of a calibrated volume that can be affixed to an 

emitting source such that the emissions inflate the bag to 

its calibrated volume. 

* * * * * 

Centrifugal compressor means any equipment that 

increases the pressure of a process natural gas or CO2 by 

centrifugal action, employing rotating movement of the 

driven shaft. 

Centrifugal compressor dry seals mean a series of 

rings around the compressor shaft where it exits the 

compressor case that operates mechanically under the 

opposing forces to prevent natural gas or CO2 from escaping 

to the atmosphere. 

Centrifugal compressor dry seal emissions mean natural 

gas or CO2 released from a dry seal vent pipe and/or the 

seal face around the rotating shaft where it exits one or 

both ends of the compressor case. 

Centrifugal compressor wet seal degassing vent 

emissions means emissions that occur when the high-pressure 

oil barriers for centrifugal compressors are depressurized 

to release absorbed natural gas or CO2. High-pressure oil 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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is used as a barrier against escaping gas in centrifugal 

compressor shafts. Very little gas escapes through the oil 

barrier, but under high pressure, considerably more gas is 

absorbed by the oil. The seal oil is purged of the 

absorbed gas (using heaters, flash tanks, and degassing 

techniques) and recirculated. The separated gas is 

commonly vented to the atmosphere. 

* * * * * 

Continuous bleed means a continuous flow of pneumatic 

supply gas to the process measurement control device (e.g. 

level control, temperature control, pressure control) where 

the supply gas pressure is modulated by the process 

condition, and then flows to the valve controller where the 

signal is compared with the process set-point to adjust gas 

pressure in the valve actuator. 

* * * * * 

Dehydrator means a device in which a liquid absorbent 

(including desiccant, ethylene glycol, diethylene glycol, 

or triethylene glycol) directly contacts a natural gas 

stream to absorb water vapor. 

Dehydrator vent emissions means natural gas and CO2

released from a natural gas dehydrator system absorbent 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(typically glycol) reboiler or regenerator to the 

atmosphere or a flare, including stripping natural gas and 

motive natural gas used in absorbent circulation pumps. 

* * * * * 

De-methanizer means the natural gas processing unit 

that separates methane rich residue gas from the heavier 

hydrocarbons (e.g., ethane, propane, butane, pentane-plus) 

in feed natural gas stream. 

* * * * * 

Desiccant means a material used in solid-bed 

dehydrators to remove water from raw natural gas by 

adsorption or absorption. Desiccants include activated 

alumina, pelletized calcium chloride, lithium chloride and 

granular silica gel material. Wet natural gas is passed 

through a bed of the granular or pelletized solid adsorbent 

or absorbent in these dehydrators. As the wet gas contacts 

the surface of the particles of desiccant material, water 

is adsorbed on the surface or absorbed and dissolves the 

surface of these desiccant particles. Passing through the 

entire desiccant bed, almost all of the water is adsorbed 

onto or absorbed into the desiccant material, leaving the 

dry gas to exit the contactor. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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* * * * * 

Gas conditions mean the actual temperature, volume, 

and pressure of a gas sample. 

* * * * * 

Gas to oil ratio (GOR) means the ratio of the volume 

of gas at standard temperature and pressure that is 

produced from a volume of oil when depressurized to 

standard temperature and pressure. 

* * * * * 

High-bleed pneumatic devices are automated, continuous 

bleed flow control devices powered by pressurized natural 

gas and used for maintaining a process condition such as 

liquid level, pressure, delta-pressure and temperature. 

Part of the gas power stream that is regulated by the 

process condition flows to a valve actuator controller 

where it vents continuously (bleeds) to the atmosphere at a 

rate in excess of 6 standard cubic feet per hour. 

* * * * * 

Intermittent bleed pneumatic devices mean automated 

flow control devices powered by pressurized natural gas and 

used for automatically maintaining a process condition such Formatted: Highlight
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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as liquid level, pressure, delta-pressure and temperature. 

These are snap-acting or throttling devices that discharge 

all or a portion of the full volume of the actuator 

intermittently when control action is necessary, but does 

not bleed continuously. 

* * * * * 

Low-bleed pneumatic devices mean automated flow 

control devices powered by pressurized natural gas and used 

for maintaining a process condition such as liquid level, 

pressure, delta-pressure and temperature. Part of the gas 

power stream that is regulated by the process condition 

flows to a valve actuator controller where it vents 

continuously (bleeds) to the atmosphere at a rate equal to 

or less than six standard cubic feet per hour. 

* * * * * 

Natural gas driven pneumatic pump means a pump that 

uses pressurized natural gas to move a piston or diaphragm, 

which pumps liquids on the opposite side of the piston or 

diaphragm. 

* * * * * 

Outer Continental Shelf means all submerged lands 

lying seaward and outside of the area of lands beneath 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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navigable waters as defined in 43 U.S.C. §1331, and of 

which the subsoil and seabed appertain to the United States 

and are subject to its jurisdiction and control. 

* * * * * 

Reciprocating compressor means a piece of equipment 

that increases the pressure of a process natural gas or CO2

by positive displacement, employing linear movement of a 

shaft driving a piston in a cylinder. 

Reciprocating compressor rod packing means a series of 

flexible rings in machined metal cups that fit around the 

reciprocating compressor piston rod to create a seal 

limiting the amount of compressed natural gas or CO2 that 

escapes to the atmosphere. 

Re-condenser means heat exchangers that cool 

compressed boil-off gas to a temperature that will condense 

natural gas to a liquid. 

* * * * * 

Sales oil means produced crude oil or condensate 

measured at the production lease automatic custody transfer 

(LACT) meter or custody transfer tank gauge. 

* * * * * 
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Sour natural gas means natural gas that contains 

significant concentrations of hydrogen sulfide (H2S)and/or 

carbon dioxide (CO2) that exceed the concentrations 

specified for commercially saleable natural gas delivered 

from transmission and distribution pipelines. 

* * * * *

 Supplier mean a producer, importer, or exporter in any 

supply category included in Table A-5, as defined by the 

corresponding subpart of this part.

Sweet Gas is natural gas with low concentrations of 

hydrogen sulfide (H2S) and/or carbon dioxide (CO2) that does 

not require (or has already had) acid gas treatment to meet 

pipeline corrosion-prevention specifications for 

transmission and distribution. 

* * * * * 

United States means the 50 States, the District of 

Columbia, the Commonwealth of Puerto Rico, American Samoa, 

the Virgin Islands, Guam, and any other Commonwealth, 

territory or possession of the United States, as well as 

the territorial sea as defined by Presidential Proclamation 

No. 5928.
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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United States Parent Company(s) means the highestlevel United States company(s) with an ownership interest 

in the facility or supplier as of December 31 of the year 

for which data are being reported. 

* * * * * 

Vapor recovery system means any equipment located at 

the source of potential gas emissions to the atmosphere or 

to a flare, that is composed of piping, connections, and, 

if necessary, flow-inducing devices, and that is used for 

routing the gas back into the process as a product and/or 

fuel. 

Vaporization unit means a process unit that performs 

controlled heat input to vaporize LNG to supply 

transmission and distribution pipelines or consumers with 

natural gas. 

* * * * * 

Well completions means the process that allows for the 

flow of petroleum or natural gas from newly drilled wells 

to expel drilling and reservoir fluids and test the 

reservoir flow characteristics, steps which may vent 

produced gas to the atmosphere via an open pit or tank. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Well completion also involves connecting the well bore to 

the reservoir, which may include treating the formation or 

installing tubing, packer(s), or lifting equipment, steps 

that do not significantly vent natural gas to the 

atmosphere. This process may also include high-rate 

flowback of injected gas, water, oil, and proppant used to 

fracture or re-fracture and prop open new fractures in 

existing lower permeability gas reservoirs, steps that may 

vent large quantities of produced gas to the atmosphere. 

Well workover means the process(es) of performing one 

or more of a variety of remedial operations on producing 

petroleum and natural gas wells to try to increase 

production. This process also includes high-rate flowback 

of injected gas, water, oil, and proppant used to refracture and prop-open new fractures in existing low 

permeability gas reservoirs, steps that may vent large 

quantities of produced gas to the atmosphere. 

Wellhead means the piping, casing, tubing and 

connected valves protruding above the earth’s surface for 

an oil and/or natural gas well. The wellhead ends where 

the flow line connects to a wellhead valve. Wellhead 

equipment includes all equipment, permanent and portable, 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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located on the improved land area (i.e. well pad) 

surrounding one or multiple wellheads. 

Wet natural gas means natural gas in which water vapor 

exceeds the concentration specified for commercially 

saleable natural gas delivered from transmission and 

distribution pipelines. This input stream to a natural gas 

dehydrator is referred to as “wet gas.” 

4. Section 98.7 is amended by reserving paragraphs 

(n) and (o), and by adding paragraphs (p) and q) to read as 

follows:

4. Section 98.7 is amended by removing paragraph (q).

§98.7 What standardized methods are incorporated by 

reference into this part?

* * * * * 

(n) [Reserved] 

(o) [Reserved] 

(p) The following material is available for purchase 

from the American Association of Petroleum Geologists, 1444 

South Boulder Avenue, Tulsa, Oklahoma 74119, (918) 584-

2555, http://www.aapg.org. 

(1) Geologic Note: AAPG-CSD Geologic Provinces Code 

Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. 

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purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 

(October 1991), pages 1644-1651, IBR approved for §98.238. 

(2) Alaska Geological Province Boundary Map, Compiled 

by the American Association of Petroleum Geologists 

Committee on Statistics of Drilling in cooperation with the 

USGS, 1978, IBR approved for §98.238. 

(q) The following material is available from the 

Energy Information Administration (EIA), 1000 Independence 

Ave., SW, Washington, DC 20585, (202) 586-8800, 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publica

tions/field_code_master_list/current/pdf/fcml_all.pdf.

(1) Oil and Gas Field Code Master List 2008, 

DOE/EIA0370(08), January 2009, IBR approved for §98.238.

(2) [Reserved]

5. Table A-4 to subpart A is amended by adding an 

entry for “Petroleum and Natural Gas Systems (subpart W)” 

at the end of the table to read as follows: 

Table A-4 to Subpart A—Source Category List for §98.2(a)(2) 

Source Categoriesa Applicable in 2010 and Future Years 

* * * * * * *

Additional Source Categoriesa Applicable in 2011 and Future Years 

Petroleum and Natural Gas Systems (subpart W) 

a Source categories are defined in each applicable subpart.

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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§98.9 Addresses.

 All requests, notifications, and communications to the 

Administrator pursuant to this part, other than submittal 

of the annual GHG report; the certificate of 

representation; and other requests, notifications or 

communications that can be submitted through the electric 

greenhouse gas reporting tool, shall be submitted to the 

following address:

 (a) For U.S. mail.

 Director, Climate Change Division

 1200 Pennsylvania Ave., NW

 Mail Code: 6207J

 Washington, DC 20460

 (b) For package deliveries.

 Director, Climate Change Division

 1310 L St., NW

 Washington, DC 20005

Subpart I – [AMENDED]

 5. Section 98.90 is ameneded by revising paragraph 

(a)(5) to read as follows:

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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§98.90 Definition of the sourece category. 

(a) * * *

(5) Any electronics manufacturing production process 

in which fluorinated heat transfer fluids are used to cool 

process equipment, to control temperature during device 

testing, to clean substrate surfaces and other parts, and 

for soldering (e.g., vapor phase reflow).

6. Section 98.92 is amended by revising paragraph (a) 

introductory text and paragraph (a)(5) to read as follows:

§98.92 GHGs to report.

(a) You must report emissions of fluorinated GHGs (as 

defined in §98.6), N2O, and fluorinated heat transfer fluids 

(as defined in §98.98). The fluorinated GHGs and 

fluorinated heat transfer fluids that are emitted from 

electronics manufacturing production processes include, but 

are not limited to, those listed in Table I–2 to this 

subpart. You must individually report, as appropriate:

* * * *

(5) Emissions of fluorinated heat transfer fluids.

* * * *

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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7. Section 98.93 is amended by revising parargraph (h) 

introductory text and the definition of “EHi” in Equation I16 to read as follows:

§98.93 Calculating GHG Emissions. 

 (h) If you use fluorinated heat transfer fluids, you 

must report the annual emissions of fluorinated heat 

transfer fluids using the mass balance approach described 

in Equation I-16 of this subpart.

* * * *

EHi = Emissions of fluorinated heat transfer fluids 

i, (metric tons/year).

* * * *

 8. Section 98.94 is amended by revising paragraph (h) 

introductory text to read as follows:

§98.94 Monitoring and QA/QC requirements.

* * * * *

 (h) You must adhere to the QA/QC procedures of this 

paragraph (h) when calculating annual gas consumption for 

each fluorinated GHG and N2O used at your facility and 

emissions from the use of fluorinated heat transfer fluids.

* * * * *

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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 9. Section 98.96 is amended by revising paragraph (r) 

to read as follows:

§98.96 Data Reporting requirements.

* * * * *

 (r) For heat transfer fluid emissions, inputs to the 

heat transfer fluid mass balance equation, Equation I–16 of 

this subpart, for each fluorinated heat transfer fluid 

used.

* * * * *

 10. Section 98.98 is amended by removing the 

definition of “Heat transfer fluids” and adding the 

definition of “Fluorinated heat transfer fluids” in 

alphabetical order to read as follows:

§98.98 Definitions.

* * * * *

Fluorinated heat transfer fluids means fluorinated 

GHGs used for temperature control, device testing, cleaning 

substrate surfaces and other parts, and soldering in 

certain types of electronics manufacturing production 

processes. For fluorinated heat transfer fluids under this 

subpart I, the lower vapor pressure limit of 1 mm of Hg in 
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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absolute at 25 degrees C in the definition of Fluorinated 

greenhouse gas in 40 CFR 98.6 shall not apply. Fluorinated 

heat transfer fluids used in the electronics manufacturing 

sector include, but are not limited to, 

perfluoropolyethers, perfluoroalkanes, perfluoroethers, 

tertiary perfluoroamines, and perfluorocyclic ethers. 

* * * * *

Table I-2 to Subpart I of Part 98—Examples of Fluorinated 

GHGs and Fluorinated Heat Transfer Fluids Used by the 

Electronics Industry 

Product Type Fluorinated GHGs and Fluorinated Heat 

Transfer Fluids Used During Manufacture

Electronics CF4, C2F6, C3F8, c-C4F8, c-C4F8O, C4F6, C5F8, 

CHF3, CH2F2, NF3, SF6, and HTFs(CF3-(O-CF(CF3)-

CF2)n-(O-CF2)m-O-CF3, CnF2n+2, CnF2n+1(O)CmF2m+1, 

CnF2nO, (CnF2n+1)3N)

6. Add subpart W – Petroleum and Natural Gas Systems 

to read as follows: 

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obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Subpart W—Petroleum and Natural Gas Systems 

Sec.

98.230 Definition of the source category. 

98.231 Reporting threshold. 

98.232 GHGs to report. 

98.233 Calculating GHG emissions. 

98.234 Monitoring and QA/QC requirements. 

98.235 Procedures for estimating missing data. 

98.236 Data reporting requirements. 

98.237 Records that must be retained. 

98.238 Definitions.

§98.230 Definition of the source category. 

(a) This source category consists of the following 

industry segments: 

(1) Offshore petroleum and natural gas production. 

Offshore petroleum and natural gas production is any 

platform structure, affixed temporarily or permanently to 

offshore submerged lands, that houses equipment to extract 

hydrocarbons from the ocean or lake floor and that 

processes and/or transfers such hydrocarbons to storage, 

transport vessels, or onshore. In addition, offshore 

production includes secondary platform structures connected 

to the platform structure via walkways, storage tanks 

associated with the platform structure and floating 
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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production and storage offloading equipment (FPSO). This 

source category does not include reporting of emissions 

from offshore drilling and exploration that is not 

conducted on production platforms. 

(2) Onshore petroleum and natural gas production. 

Onshore petroleum and natural gas production means all 

equipment on a well pad or associated with a well pad 

(including but not limited to compressors, generators,

dehydrators, storage vessels, or storage facilities), and 

portable non-self-propelled equipment which includes on a 

well pad or associated with a well pad (including well 

drilling and completion equipment, workover equipment, 

gravity separation equipment, auxiliary non-transportationrelated equipment, and leased, rented or contracted 

equipment) used in the production, extraction, recovery, 

lifting, stabilization, separation or treating of petroleum 

and/or natural gas (including condensate). This equipment 

also includes associated storage or measurement vessels and 

all enhanced oil recovery (EOR) operations using CO2, and 

all petroleum and natural gas production located on 

islands, artificial islands, or structures connected by a 

causeway to land, an island, or artificial island. 

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obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(3) Onshore natural gas processing. Natural gas 

processing means the separation ofseparates and recovers

natural gas liquids (NGLs) and/or other non-methane gases 

and liquids from a stream of from produced natural gas, or

the separation of NGLs into one or more component mixtures. 

Separation includes using equipment performing one or more 

of the following processes: forced extraction of natural 

gas liquids, sulfur and carbon dioxide removal, oil and 

condensate removal, water removal, separation of natural 

gas liquids, sulfur and carbon dioxide removal,

fractionation of NGLs, or other processes, and also the 

capture of CO2 separated from natural gas streams. This 

segment also includes all residue gas compression equipment 

owned or operated by the natural gas processing 

plant.facility, whether inside or outside the processing 

facility fence. This industry segment includes processing 

plants that fractionate gas liquids, and processing plants 

that do not fractionate gas liquids but have an annual 

average throughput of 25 MMscf per day or great.source 

category does not include reporting of emissions from 

gathering lines and boosting stations. This source category 

includes: 

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purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(i) All processing facilities that fractionate.

(ii) All processing facilities that do not 

fractionate with annual average throughput of 25 MMscf per 

day or greater. 

(4) Onshore natural gas transmission compression. 

Onshore natural gas transmission compression means any 

stationary combination of compressors that move natural gas 

at elevated pressure from production fields, or natural 

gas processing plants,facilities orin other transmission

compressors through transmission pipelines to natural gas 

distribution pipelines, LNG storage facilities, or into 

underground storage. In addition, transmission compressor 

station may includes equipment for liquids separation,

natural gas dehydration, and tanks for the storage of water 

and hydrocarbon liquids. Residue (sales) gas compression

that is part of operated by natural gas processing 

facilities are included in the onshore natural gas 

processing plants are included in the onshore natural gas 

processing segment and are excluded from this segment. 

This source category also does not include reporting of 

emissions from gathering lines and boosting stations –

these sources are currently not covered by subpart W.

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(5) Underground natural gas storage. Underground 

natural gas storage means subsurface storage, including 

depleted gas or oil reservoirs and salt dome caverns that 

store natural gas that has been transferred from its 

original location for the primary purpose of load balancing 

(the process of equalizing the receipt and delivery of 

natural gas); natural gas underground storage processes and 

operations (including compression, dehydration and flow 

measurement, and excluding transmission pipelines); and all 

the wellheads connected to the compression units located at 

the facility that inject and recover natural gas into and 

from the underground reservoirs. 

(6) Liquefied natural gas (LNG) storage. LNG storage 

means onshore LNG storage vessels located above ground, 

equipment for liquefying natural gas, compressors to 

capture and re-liquefy boil-off-gas, re-condensers, and 

vaporization units for re-gasification of the liquefied 

natural gas. 

(7) LNG import and export equipment. LNG import 

equipment means all onshore or offshore equipment that 

receives imported LNG via ocean transport, stores LNG, regasifies LNG, and delivers re-gasified natural gas to a 
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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natural gas transmission or distribution system. LNG 

export equipment means all onshore or offshore equipment 

that receives natural gas, liquefies natural gas, stores 

LNG, and transfers the LNG via ocean transportation to any 

location, including locations in the United States. 

(8) Natural gas distribution. Natural gas 

distribution means the distribution pipelines (not 

interstate transmission pipelines or intrastate 

transmission pipelines) and metering and regulating 

equipment at metering-regulating city gate stations, and

excluding customer meters, that physically deliver natural 

gas to end users and is that are operated by a Local 

Distribution Company (LDC)within a single state that is 

regulated as a separate operating company by a public 

utility commission or that is operated as an independent 

municipally-owned distribution system. This segment also

excludes customer meters and regulators, infrastructure,

and pipelines (both interstate and intrastate) delivering 

natural gas directly to major industrial users and "farm 

taps" upstream of the local distribution company inlet. 

(b) [Reserved] 

§98.231 Reporting threshold.

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(a) You must report GHG emissions under this subpart 

if your facility contains petroleum and natural gas systems 

and the facility meets the requirements of §98.2(a)(2). 

Facilities must report emissions from the onshore petroleum 

and natural gas production industry segment only if 

emission sources specified in paragraph §98.232(c) emit 

25,000 metric tons of CO2 equivalent or more per year. 

Facilities must report emissions from the natural gas 

distribution industry segment only if emission sources 

specified in paragraph §98.232(i) emit 25,000 metric tons 

of CO2 equivalent or more per year. 

 (b) For applying the threshold defined in 

§98.2(a)(2), natural gas processing facilities must also 

include owned or operated residue gas compression 

equipment. 

§98.232 GHGs to report. 

(a) You must report CO2, CH4, and N2O emissions from 

each industry segment specified in paragraph (b) through 

(i) of this section, CO2, CH4, and N2O emissions from each 

flare as specified in paragraph (j) of this section, and 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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stationary and portable combustion emissions as applicable 

as specified in paragraph (k) of this section. 

(b) For offshore petroleum and natural gas 

production, report CO2, CH4, and N2O emissions from equipment 

leaks, vented emission, and flare emission source types as 

identified in the data collection and emissions estimation 

study conducted by BOEMRE in compliance with 30 CFR 250.302 

through 304. Offshore platforms do not need to report 

portable emissions. 

(c) For an onshore petroleum and natural gas 

production facility, report CO2, CH4, and N2O emissions from 

only the following source types on a single well- pad or 

associated with a well pad: 

(1) Natural gas pneumatic device venting. 

(2) [Reserved] 

(3) Natural gas driven pneumatic pump venting. 

(4) Well venting for liquids unloading. 

(5) Gas well venting during well completions without 

hydraulic fracturing. 

(6) Gas well venting during well completions with 

hydraulic fracturing. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 38 of 206

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(7) Gas well venting during well workovers without 

hydraulic fracturing. 

(8) Gas well venting during well workovers with 

hydraulic fracturing. 

(9) Flare stack emissions. 

(10) Storage tanks vented emissions from produced 

hydrocarbons. 

(11) Reciprocating compressor rod packing venting. 

(12) Well testing venting and flaring. 

(13) Associated gas venting and flaring from produced 

hydrocarbons. 

(14) Dehydrator vents. 

(15) [Reserved] 

(16) EOR injection pump blowdown. 

(17) Acid gas removal vents. 

(18) EOR hydrocarbon liquids dissolved CO2. 

(19) Centrifugal compressor venting. 

(20) [Reserved] 

(21) Equipment leaks from valves, connectors, open 

ended lines, pressure relief valves, pumps, flanges, and 

other equipment leak sources (such as instruments, loading 
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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arms, stuffing boxes, compressor seals, dump lever arms, 

and breather caps). 

(22) You must use the methods in §98.233(z) and 

report under this subpart the emissions of CO2, CH4, and N2O 

from stationary or portable fuel combustion equipment that 

cannot move on roadways under its own power and drive 

train, and that are located at an onshore petroleum and 

natural gas production facility as defined in 

§98.238.production well pad. Stationary or portable 

equipment are the following equipment which are integral to 

the extraction, processing or movement of oil or natural 

gas: well drilling and completion equipment, workover 

equipment, natural gas dehydrators, natural gas 

compressors, electrical generators, steam boilers, and 

process heaters. 

(d) For onshore natural gas processing, report CO2,

and CH4, and N2O emissions from the following sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor venting. 

(3) Blowdown vent stacks. 

(4) Dehydrator vents. 

(5) Acid gas removal vents. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(6) Flare stack emissions. 

(7) Equipment leaks from valves, connectors, open 

ended lines, pressure relief valves, and meters. 

(e) For onshore natural gas transmission compression, 

report CO2, and CH4, and N2O emissions from the following 

sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor venting. 

(3) Transmission storage tanks. 

(4) Blowdown vent stacks. 

(5) Natural gas pneumatic device venting. 

(6) [Reserved] 

(7) Equipment leaks from valves, connectors, open 

ended lines, pressure relief valves, and meters. 

(f) For underground natural gas storage, report CO2,

and CH4, and N2O emissions from the following sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor venting. 

(3) Natural gas pneumatic device venting. 

(4) [Reserved] 

(5) Equipment leaks from valves, connectors, open 

ended lines, pressure relief valves, and meters. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 41 of 206

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(g) For LNG storage, report CO2, and CH4, and N2O

emissions from the following sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor venting. 

(3) Equipment leaks from valves; pump seals; 

connectors; vapor recovery compressors, and other equipment 

leak sources. 

(h) LNG import and export equipment, report CO2, and

CH4, and N2O emissions from the following sources: 

(1) Reciprocating compressor rod packing venting. 

(2) Centrifugal compressor venting. 

(3) Blowdown vent stacks. 

(4) Equipment leaks from valves, pump seals, 

connectors, vapor recovery compressors, and other equipment 

leak sources. 

(i) For natural gas distribution, report CO2, and CH4,

and N2O emissions from the following sources: 

(1) Meters, regulators, and associated equipment at 

above grade transmission-distribution transfer stations, 

Above ground meters and regulators at custody transfer city 

gate stations, including equipment leaks from connectors, 

block valves, control valves, pressure relief valves, 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 42 of 206

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orifice meters, regulators, and open ended lines. Customer 

meters are excluded.

(2) Equipment leaks from vaults at below grade 

transmission-distribution transfer stations.

(32) Meters, regulators, and associated equipment at 

above grade metering-regulating station.Above ground meters 

and regulators at non-custody transfer city gate stations, 

including station equipment leaks. Customer meters are 

excluded.

(43) Equipment leaks from vaults at below grade 

metering-regulating stations.Below ground meters and 

regulators and vault equipment leaks. Customer meters are 

excluded.

(54) Pipeline main equipment leaks. 

(65) Service line equipment leaks. 

(76) Report under subpart W of this part the 

emissions of CO2, CH4, and N2O emissions from stationary 

fuel combustion sources following the methods in 

§98.233(z). 

(j) [Reserved]All applicable industry segments must 

report the CO2, CH4, and N2O emissions from each flare. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(k) Report under subpart C of this part (General 

Stationary Fuel Combustion Sources) the emissions of CO2, 

CH4, and N2O from each stationary fuel combustion unit by 

following the requirements of subpart C except for 

facilities under onshore petroleum and natural gas

production and natural gas distribution. Onshore petroleum 

and natural gas production facilities must report 

stationary and portable combustion emissions as specified 

in paragraph (c) of this section. Natural gas distribution 

facilities must report stationary combustion emissions as 

specified in paragraph (i) of this section. 

(l) You must report under subpart PP of this part 

(Suppliers of Carbon Dioxide), CO2 emissions captured and 

transferred off site by following the requirements of 

subpart PP. 

§98.233 Calculating GHG emissions. You must calculate and 

report the annual GHG emissions as prescribed in this 

section. For actual conditions, reporters must use average 

atmospheric conditions or typical operating conditions as 

applicable to the respective monitoring methods in this 

section. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(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. 

Masss,i  Count * EF * GHGi *Convi *T (Eq. W-1) 

Where: 

Masss,i = Annual total mass GHG emissions in metric tons 

CO2e per year at standard conditions from a 

natural gas pneumatic device vent, for GHG i. 

Count = Total number of continuous high bleed, 

continuous low bleed, or intermittent bleed 

natural gas pneumatic devices of each type as 

determined in paragraph (a)(1)and (a)(2) of 

this section. 

EF = Population emission factors for natural gas 

pneumatic device venting listed in Tables W1A, W-3, and W-4 of this subpart for onshore 

petroleum and natural gas production, onshore 

natural gas transmission compression, and 

underground natural gas storage facilities, 

respectively. 

GHGi = For onshore petroleum and natural gas 

production facilities, onshore natural gas 

transmission compression, and underground 

natural gas storage, concentration of GHGi i, 

CH4, or CO2, in produced natural gas as defined 

in paragraph (u)(2)(i) of this section.; for 

facilities listed in §98.230(a)(43) andthrough 

(a)(58), GHGi equals 10.952 for CH4 and 1x10-2

for CO2.

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 45 of 206

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Convi = Conversion from standard cubic feet to metric 

tons CO2e; 0.000410 for CH4, and 0.00005357 for 

CO2.

T = Total number of hours in the operating year 

the devices were operational.

24 * 365 = Conversion to yearly emissions estimate.

(1) For onshore petroleum and natural gas production, 

provide the total number of continuous high bleed, 

continuous low bleed, or intermittent bleed natural gas 

pneumatic devices of each type as follows: 

(i) In the first calendar year, for the total number 

of each type, you may count the total of each type, or 

count any percentage number of each type plus an 

engineering estimate based on best available data of the 

number not counted. 

(ii) In the second consecutive year, for the total 

number of each type, you may count the total of each type, 

or count any percentage number of each type plus an 

engineering estimate based on best available data of the 

number not counted. 

(iii) In the third consecutive calendar year, 

complete the count of all pneumatic devices, including any 

changes to equipment counted in prior years. 

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(iv) For the calendar year immediately following the 

third consecutive calendar year, and for calendar years 

thereafter, facilities must update the total count of 

pneumatic devices and adjust accordingly to reflect any 

modifications due to changes in equipment. 

(2) For onshore natural gas transmission compression 

and underground natural gas storage, all natural gas 

pneumatic devices must be counted in the first year and 

updated every calendar year.

(3) For all industry segments, determine the type of 

pneumatic device using engineering estimates based on best 

available information.

(b) [Reserved] 

(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. 

Masss,i  Count * EF * GHGi *Convi * T (Eq. W-2) 

Where: 

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Masss,i = Annual total mass GHG emissions in metric tons 

CO2e per year at standard conditions from all 

natural gas pneumatic pump venting, for GHG i. 

Count = Total number of natural gas pneumatic pumps. 

EF = Population emission factors for natural gas 

pneumatic pump venting listed in Tables W-1A 

of this subpart for onshore petroleum and 

natural gas production. 

GHGi = Concentration of GHGi i, CH4, or CO2, in 

produced natural gas as defined in paragraph 

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

Convi = Conversion from standard cubic feet to metric 

tons CO2e; 0.000410 for CH4, and 0.00005357 for 

CO2.

T = Total number of hours in the operating year 

the pumps were operational.

24 * 365 = Conversion to yearly emissions estimate. 

(d) Acid gas removal (AGR) vents. For AGR vent 

(including processes such as amine, membrane, molecular 

sieve or other absorbents and adsorbents), calculate 

emissions for CO2 only (not CH4) vented directly to the 

atmosphere or through a flare, engine (e.g. permeate from a 

membrane or de-adsorbed gas from a pressure swing adsorber 

used as fuel supplement), or sulfur recovery plant using 

any of the calculation methodologies described in paragraph 

(d) of this section, as applicable. 

(1) Calculation Methodology 1. If you operate and 

maintain a CEMS that has both a CO2 concentration monitor 

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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and volumetric flow rate monitormeasures CO2 emissions 

according to subpart C of this part, you must calculate CO2

emissions under this subpart by following the Tier 4 

Calculation Methodology and all associated calculation, 

quality assurance, reporting, and recordkeeping

requirements for Tier 4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). If a CO2

concentration monitor and CEMS and/or volumetric flow rate 

monitor are not available, you may elect to install a CO2

concentration monitor and a volumetric flow rate monitor

CEMS that complyies with all of the requirements specified 

for the Tier 4 Calculation Methodology in subpart C of this 

part (General Stationary Fuel Combustion). The calculation 

and reporting of CH4 and N2O emissions is not required as 

part of the Tier 4 requirements for AGRs.

(2) Calculation Methodology 2. If CEMS is not 

available but a vent meter is available, use the CO2

composition and annual volume of vent gas to calculate 

emissions using Equation W-3 of this section. 

Ea,CO2 = VS * VolCO2 (Eq. W-3) 

Where: 

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Ea,CO2 = Annual volumetric CO2 emissions at actual 

conditions, in cubic feet per year. 

VS = Total annual volume of vent gas flowing out of 

the AGR unit in cubic feet per year at actual 

conditions as determined by flow meter using 

methods set forth in §98.234(b). 

VolCO2 = Volume fraction of CO2 content in vent gas out 

of the AGR unit as determined in (d)(6) of 

this section. 

(3) Calculation Methodology 3. If using CEMS or a 

vent meter is not an optionavailable, you may use the inlet 

or outlet gas flow rate of the acid gas removal unit to 

calculate emissions for CO2 using Equation W-4 of this 

section. 

  I O

I O

a CO Vol Vol

Vol Vol

V E  



 





   * 1 ( ) , 2 (Eq. W-4) 

Where: 

Ea,CO2 = Annual volumetric CO2 emissions at actual 

condition, in cubic feet per year. 

V = Total annual volume of natural gas flow into 

or out of the AGR unit in cubic feet per year 

at actual condition as determined using 

methods specified in paragraph (d)(5) of this 

section. 

α = Factor is 1 if the outlet stream flow is 

measured. Factor is 0 if the inlet stream 

flow is measured. 

VolI = Volume fraction of CO2 content in natural gas 

into the AGR unit as determined in paragraph 

(d)(7) of this section. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 50 of 206

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VolO = Volume fraction of CO2 content in natural gas 

out of the AGR unit as determined in paragraph 

(d)(8) of this section. 

(4) Calculation Methodology 4. If CEMS or a vent 

meter is not available, you may Ccalculate emissions using 

any standard simulation software packages, such as 

AspenTech HYSYS®

 and API 4679 AMINECalc, that uses the PengRobinson equation of state, and speciates CO2 emissions. A 

minimum of the following determined for typical operating 

conditions over the calendar year by engineering estimate 

and process knowledge based on best available data must be 

used to characterize emissions: 

(i) Natural gas feed temperature, pressure, and flow 

rate. 

(ii) Acid gas content of feed natural gas. 

(iii) Acid gas content of outlet natural gas. 

(iv) Unit operating hours, excluding downtime for 

maintenance or standby. 

(v) Exit temperature of natural gas. 

(vi) Solvent pressure, temperature, circulation rate, 

and weight. 

(5) Record the gas flow rate of the inlet and outlet 

natural gas stream of an AGR unit using a meter according 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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to methods set forth in §98.234(b). If you do not have a 

continuous flow meter, either install a continuous flow 

meter or use an engineering calculation to determine the 

flow rate. 

(6) If continuous gas analyzer is not available on 

the vent stack, either install a continuous gas analyzer or 

take quarterly gas samples from the vent gas stream to 

determine VolCO2 according to methods set forth in 

§98.234(b). 

(7) If a continuous gas analyzer is installed on the 

inlet gas stream, then the continuous gas analyzer results 

must be 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). 

(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. 

(i) If a continuous gas analyzer is installed on the 

outlet gas stream, then the continuous gas analyzer results 

must be used. If a continuous gas analyzer is not 

available, you may install a continuous gas analyzer. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(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). 

(iii) Use sales line quality specification for CO2 in 

natural gas. 

(9) Calculate CO2 volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section. 

(10) Mass CO2 emissions shall be calculated from 

volumetric CO2 emissions using calculations in paragraph (v) 

of this section. 

(11) Determine if emissions from the AGR unit are 

recovered and transferred outside the facility. Adjust the 

emission estimated in paragraphs (d)(1) through (d)(10) of 

this section downward by the magnitude of emission 

recovered and transferred outside the facility. 

(e) Dehydrator vents. For dehydrator vents, 

calculate annual CH4, CO2 and N2O (when flared) emissions 

using any of the calculation methodologies described in 

paragraphs (e) (1) or (e)(2) of this section. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 53 of 206

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(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 PengRobinson 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: 

(i) Feed natural gas flow rate. 

(ii) Feed natural gas water content. 

(iii) Outlet natural gas water content. 

(iv) Absorbent circulation pump type (natural gas 

pneumatic/ air pneumatic/ electric). 

(v) Absorbent circulation rate. 

(vi) Absorbent type: including triethylene glycol 

(TEG), diethylene glycol (DEG) or ethylene glycol (EG). 

(vii) Use of stripping natural gas. Formatted: No underline, Font color: Auto,

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(viii) Use of flash tank separator (and disposition 

of recovered gas). 

(ix) Hours operated. 

(x) Wet natural gas temperature and pressure. 

(xi) Wet natural gas composition. Determine this 

parameter by selecting one of the methods described under 

paragraph (e)(2)(xi)(e)(1)(xi) of this section. 

(A) Use the wet natural gas composition as defined in 

paragraph (u)(2)(i)or (u)(2)(ii) of this section. 

(B) If wet natural gas composition cannot be 

determined using paragraph (u)(2)(i)or (u)(2)(ii) of this 

section, select a representative analysis. 

(C) You may use an appropriate standard method 

published by a consensus-based standards organization if 

such a method exists or you may use an industry standard 

practice as specified in §98.234(b)(1) to sample and 

analyze wet natural gas composition. 

(D) If only composition data for dry natural gas is 

available, assume the wet natural gas is saturated. 

(2) Calculation Methodology 2. Calculate annual CH4

and CO2 emissions from glycol dehydrators with annual 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 55 of 206

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average daily throughput less than 0.4 million cubic feet 

per day using Equation W-5 of this section: 

Es,i EFi *Count*1000 (Eq. W-5) 

Where: 

Es,i = Annual total volumetric GHG emissions (either 

CO2 or CH4) at standard conditions in cubic 

feet. 

EFi = Population emission factors for glycol 

dehydrators in thousand standard cubic feet 

per dehydrator per year. Use 74.5 for CH4 and 

3.26 for CO2 at 68°F and 14.7 psia or 73.4 for 

CH4 and 3.21 for CO2 at 60°F and 14.7 psia. 

Count = Total number of glycol dehydrators with 

throughput less than 0.4 million cubic feet. 

1000 = Conversion of EFi in thousand standard cubic

feet to cubic feet. 

(3) Determine if dehydrator unit has vapor recovery. 

Adjust the emissions estimated in paragraphs (e)(1) or 

(e)(2) of this section downward by the magnitude of 

emissions captured. 

(4) Calculate annual emissions from dehydrator vents 

to flares or regenerator fire-box/fire tubes as follows: 

(A) Use the dehydrator vent volume and gas 

composition as determined in paragraphs (e)(1) and (e)(2) 

of this section. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 56 of 206

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(B) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine dehydrator 

vent emissions from the flare or regenerator combustion gas 

vent. 

(5) Dehydrators that use desiccant shall calculate 

emissions from the amount of gas vented from the vessel 

every time it is depressurized for the desiccant refilling 

process using Equation W-6 of this section. Desiccant 

dehydrators covered in (e)(5) of this section do not have 

to report emissions under (i) of this section. 

Es,n = (H*D2

*P*P2*%G*365days/yr) (Eq. W-6) 

 (4*P1*T*1,000cf/Mcf*100) 

Where: 

Es,n = Annual natural gas emissions at standard 

conditions in cubic feet. 

H = Height of the dehydrator vessel (ft). 

D = Inside diameter of the vessel (ft). 

P1 = Atmospheric pressure (psia). 

P2 = Pressure of the gas (psia). 

P = pi (3.14). 

%G = Percent of packed vessel volume that is gas. 

T = Time between refilling (days). 

100 = Conversion of %G to fraction. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(6) For glycol dehydrators, both CH4 and CO2 mass 

emissions shall be calculated from volumetric GHGi emissions 

using calculations in paragraph (v) of this section. For 

dehydrators that use desiccant, bBoth 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. 

(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. 

(1) Calculation Methodology 1. For one well of each 

unique well tubing diameter grouping and pressure grouping 

in each sub-basin category producing horizon/formation 

combination in each gas producing field (see §98.238 for 

the definitions of tubing diameter grouping, pressure 

grouping, and sub-basin categoryField), where gas wells are 

vented to the atmosphere to expel liquids accumulated in 

the tubing, a recording flow meter shall be installed on 

the vent line used to vent gas from the well (e.g. on the 

vent line off the wellhead separator or atmospheric storage 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 58 of 206

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tank) according to methods set forth in §98.234(b). 

Calculate emissions from well venting for liquids unloading 

using Equation W-7 of this section. 

 h tEa,n Th,t FRh,t * (Eq. W-7) 

Where: 

Ea,n = Annual natural gas emissions for wells of the 

same tubing diameter grouping and pressure 

grouping at actual conditions in cubic feet. 

Th,t = Cumulative amount of time in hours of venting 

from all wells of the same tubing diameter

grouping p and pressure grouping q (t) and 

producing horizon (h)/formation combination

during the year. 

FRh,t = Average flow rate in cubic feet per hour of the 

measured well venting for the duration of the 

liquids unloading, under actual conditions as 

determined in paragraph (f)(1)(i) of this 

section.

h = Total number of different tubing diameter 

groupings.

p = Tubing diameter grouping 1 through h.

t = Total number of pressure groupings.

q = Pressure grouping 1 through t.

(i) Determine the well vent average flow rate as 

specified under paragraph (f)(1)(i) of this section. 

(A) The average flow rate per hour of venting is 

calculated for each unique tubing diameter grouping and 

pressure grouping in each sub-basin category producing 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 59 of 206

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horizon/formation combination in each producing field by 

averaging dividing the recorded total flow rates forby the

the recorded time (in hours) of one representative well 

venting to the atmospherefor a single liquid unloading with 

venting to the atmosphere. 

(B) This average flow rate is applied to all wells in 

the field that have the same tubing diameter and producing 

horizon/formation combinationpressure grouping that have 

the same tubing diameter grouping, for the number of hours 

of venting these wells. 

(C) A new average flow rate is calculated every other 

calendar year for each reporting field and horizonsub-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.

(ii) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(2) Calculation Methodology 2. Calculate the total 

emissions forfrom each well venting for liquids unloading 

using Equation W-8 of this section. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 60 of 206

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           

















          

W

p

V

q

s n p p p p q q p q p

p

E V CD WD SP SFR HR Z 1 1

, ,

3 2

, 0.37 10 1.0 (Eq. W-8)

Ea,n = {(0.37×10-3)*CD2*WD*SP*NV}+{SFR*(HR-1.0)*Z} (Eq. W-8)

Where: 

Esa,n = Annual natural gas emissions at actual 

conditions, in cubic feet/year. 

W = Total nNumber of wells with well venting for 

liquids unloading at the facility

0.37×10-3 = {3.14 (pi)/4}/{14.7*144} (psia converted to 

pounds per square feet). 

CDpW = Casing diameter for each well, p, in (inches). 

WDpW = Well depth from the lowest packer to the 

bottom of the wellto first producing horizon

for each well, in (feet). 

SPpW = Shut-in pressure for each well, p, in pounds 

square inch atmoshphere (psia). 

VpWNV = Number of vents per year per well, p. 

SFRpW = Average sales flow rate of each gas well, p, 

at standard conditions in cubic feet per hour. 

Use Equation W-33 to calculate the sales in 

cubic feet per hour. 

HRQV,PW = Hours that eachthe well, p, was left open to 

the atmosphere during each unloading eventq. 

1.0 = Hours for average well to blowdown casing 

volume at shut-in pressure. 

ZV,WQ,P = If HRV,W Q,Pis less than 1.0 then ZV,W Q,Pis equal to 

0. If HRV,W Q,Pis greater than or equal to 1.0 

then ZV,WQ,P is equal to 1.

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 61 of 206

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(i) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section.

(ii) [Reserved]

(3) Calculation Methodology 3. Calculate emissions 

from each well venting to the atmosphere for liquids 

unloading with plunger lift assist using Equation W-9 of 

this section. 

           







 



          

W

p

V

q

s n p p p p q q p q p

p

E V TD WD SP SFR HR Z 1 1

, ,

3 2

, 0.37 10 0.5

 (Eq. W-9)

Ea,n = {(0.37×10-3)*TD2*WD*SP*NV}+{SFR*(HR-0.5)*Z} (Eq. W-9)

Where: 

Ea,ns,n = Annual natural gas emissions at actual 

standard conditions, in cubic feet/year. 

W = Number of wells with well venting for liquids 

unloading at the facility.

0.37×10-3 = {3.14 (pi)/4}/{14.7*144} (psia converted to 

pounds per square feet). 

TDWp = Tubing diameter for each well, p, in (inches). 

WDWp = Tubing depth to plunger bumper for each well,

p, in (feet). 

SPWp = Sales line pressure for each well, p, in 

pounds per square in atmospheric (psia). 

NVVp = Number of vents per year per wellfor each 

well, p. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 62 of 206

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SFRWp = Average sales flow rate of each gas well, p, 

at standard conditions in cubic feet per hour.

Use Equation W-33 to calculate the sales flow 

rate at standard conditions.

HRV,WQ,P = Hours that eachthe well, p, was left open to 

the atmosphere during each unloading eventq. 

0.5 = Hours for average well to blowdown tubing 

volume at sales line pressure. 

ZV,WQ,P = If HRV,W Q,Pis less than 0.5 then ZV,W Q,Pis equal to 

0. If HRV,WQ,P is greater than or equal to 0.5 

then ZV,WQ,P is equal to 1.

(i) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(ii) [Reserved]

(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. 

(g) Gas well venting during completions and workovers 

from hydraulic fracturing. Calculate CH4, CO2 and N2O (when 

flared) annual emissions from gas well venting during 

completions involving hydraulic fracturing in wells and 

well workovers using Equation W-10 of this section. Both CH4

and CO2 volumetric and mass emissions shall be calculated 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 63 of 206

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from volumetric total gas emissions using calculations in 

paragraphs (u) and (v) of this section. 

(-10W .Eq (݅ ሿ ݅ܩܵ െ ݅ܨ݊ܧ െ ܴܲ݅ כ ܯܴܨ כ ܶ ሾ ∑ ൌ௡ ,௔ܧ

Ea,n = (T * FR) – EnF - SG (Eq. W-10)

Where: 

Ea,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 combination. 

T = Cumulative amount of time in hours of eachall

well (p) completion or workover venting in a subbasin and well type combinationfield during the 

year reporting.

FRM = Venting to 30-day production ratio from Equation 

W-12.

PFRp = First 30-day aAverage production flow rate in 

standard cubic feet per hour of each well (p), 

under actual conditions, converted to standard 

conditions, as required in paragraph (g)(1) of 

this section. 

EnFp = 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 EnF is 0. If 

injected gas is CO2 then EnF is 0. 

SGp = Volume of natural gas in cubic feet at standard 

conditions that was recovered into a sales 

pipeline for well p as per paragraph (g)(3) of 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 64 of 206

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this section. If no gas was recovered for sales, 

SG is 0.

W = Total number of wells completed or worked over 

using hydraulic fracturing in a sub-basin and 

well type combination.

(1) The average flow rate for gas well venting to the 

atmosphere or to a flare during well completions and 

workovers from hydraulic fracturing shall be determined 

using measurement(s) from either of the calculation 

methodologies described in this paragraph (g)(1) of this 

section. The number of measurements shall be determined as 

follows: One measurement for less than or equal to 25 

completions/workovers; two measurements for 26 to 50 

completions/workovers; three measurements for 51 to 100 

completions/workovers; four measurements for 101 to 250 

completions/workovers; and five measurements for greater 

than 250 completions/workovers.

(i) Calculation Methodology 1. For one well 

completion(s) in each gas producing sub-basin category and 

well type (horizontal or vertical)combinationfield and for 

one well workover in each gas producing field, a recording 

flow meter (digital or analog) shall be installed on the 

vent line, ahead of a flare if used, to measure the 

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 65 of 206

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backflow venting event according to methods set forth in 

§98.234(b). 

(A) The average flow rate in cubic feet per hour of 

venting to the atmosphere or routed to a flare is 

determined from the flow recording over the period of 

backflow venting. 

(B) The respective flow rates are applied to all well 

completions in the producing field and to all well 

workovers in the producing field for the total number of 

hours of venting of each of these wells. 

(C) New flow rates for completions and workovers are 

measured every other calendar year for each reporting gas 

producing field and gas producing geologic horizon in each 

gas producing field starting in the first calendar year of 

data collection. 

(D) Calculate total volumetric flow rate at standard 

conditions using calculations in paragraph (t) of this 

section.

(ii) Calculation Methodology 2. For one horizontal

well completion and one vertical well completion in each 

gas producing field sub-basin category and for one well 

horizontal workover and one well vertical workover in each 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 66 of 206

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gas producing sub-basin categoryfield, 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 intermittent well flow rate of gas 

during venting to the atmosphere or a flare. Calculate 

emissions using Equation W-11A of this section for subsonic 

flow or Equation W-11B2 of this section for sonic flow.:

Use equation W-11C of this section to determine whether 

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:

































 













 

1.758

1

2

1.515

1

5 2 1.27*10 * * 3430* * P

P

P

P

FR A Tu (Eq. W-11A) 

Where: 

FR = Average flow rate in cubic feet per hour, 

under subsonic flow conditions. 

A = Cross sectional area of orifice (m2

). 

P1 = Upstream pressure (psia). 

Tu = Upstream temperature (degrees Kelvin). 

P2 = Downstream pressure (psia). 

3430 = Constant with units of m2

/(sec2 * K). 

1.27*105

 = Conversion from m3/second to ft3/hour. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 67 of 206

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FR A Tu 1.27 *10 * * 187.08 * 5  (Eq. W-11B2) 

Where: 

FR = Average flow rate in cubic feet per hour, under

sonic flow conditions. 

A = Cross sectional area of orifice (m2

). 

Tu = Upstream temperature (degrees Kelvin). 

187.08 = Constant with units of m2/(sec2 * K). 

1.27*105 = Conversion from m3/second to ft3/hour.

2

1

P R  P

 (Eq. W-11C)

Where:

R = Pressure ratio

P1 = Pressure upstream of the restriction orifice in 

pounds per square inch absolute.

P2 = Pressure downstream of the restriction orifice in 

pounds per square inch absolute.

(iiiA) The average flow rate in cubic feet per hour 

of venting across the choke is calculated for one well 

completion in each gas producing field and for one well 

workover in each gas producing field by averaging the gas 

flow rates during venting to the atmosphere or routing to a 

flare.The emissions to 30-day production ratio is 

calculated using Equation W-12 of this section. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 68 of 206

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





  W

p

p

W

p

p

PR

FR

FRM

1

1 (Eq. W-12)

Where:

FRM = Emissions to 30-day production ratio.

FRp = Measured flow rate from Calculation 

Methodology 1 or estimated flow rate from 

Calculation Methodology 2 in standard cubic feet 

per hour for well(s) p for each sub-basin and 

well type (horizontal or vertical) combination.

PRp = First 30-day production rate in standard cubic 

feet per hour for each well p that was measured 

in the sub-basin and well type combination.

W = Number of wells completed or worked over using 

hydraulic fracturing in a sub-basin and well type 

formation.

 

(ivB) The respective flow rates for horizontal and 

vertical wells are applied to all horizontal and vertical 

well completions in the gas producing field sub-basin and 

well type combination and to all horizontal and vertical 

well workovers, respectively, in the gas producing field 

sub-basin and well type combination for the total number of 

hours of venting of each of these wells. 

Field Code Changed

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 69 of 206

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(vC) New fFlow rates for horizontal and vertical gas 

well completions and horizontal and vertical gas well

workovers in each field sub-basin category shall be 

calculated once every two years for each reporting gas 

producing field and geologic horizon in each gas producing 

field starting in the first calendar year of data 

collection. 

(D) Calculate total volumetric flow rate at standard 

conditions using calculations in paragraph (t) of this 

section.

(2) The volume of CO2 or N2 injected into the well 

reservoir during energized hydraulic fractures will be 

measured using an appropriate meter as described in 

98.234(b) or using receipts of gas purchases that are used 

for the energized fracture job. 

(i) Calculate gas volume at standard conditions using 

calculations in paragraph (t) of this section. 

(ii) [Reserved] 

(3) The volume of recovered completion or workover gas 

sent to a sales line will be measured using existing 

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 70 of 206

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company records. If data does not exist on sales gas, then 

an appropriate meter as described in 98.234(b) may be used. 

(i) Calculate gas volume at standard conditions using 

calculations in paragraph (t) of this section. 

(ii) [Reserved] 

(4) Both CH4 and CO2 volumetric and mass emissions 

shall be calculated from volumetric total emissions using 

calculations in paragraphs (u) and (v) of this section. 

(5) Determine if the well completion or workover from 

hydraulic fracturing recovered gas with purpose designed 

equipment that separates saleable gas from the backflow, 

and sent this gas to a sales line (e.g. reduced emissions 

completion or workovers). 

(i) Use the factor SG in Equation W-10 of this 

section, to adjust the emissions estimated in paragraphs 

(g)(1) through (g)(4) of this section by the magnitude of 

emissions captured using reduced emission completions as 

determined by engineering estimate based on best available 

data. 

(ii) [Reserved] 

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 71 of 206

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(6) Calculate annual emissions from gas well venting 

during well completions and workovers from hydraulic 

fracturing to flares as follows: 

(i) Use the total gas well venting volume during well 

completions and workovers as determined in paragraph (g) of 

this section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine gas well 

venting during well completions and workovers using 

hydraulic 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. 

(h) Gas well venting during completions and workovers 

without hydraulic fracturing. Calculate CH4, CO2 and N2O 

(when flared) emissions from each gas well venting during 

well completions and workovers not involving hydraulic 

fracturing and well workovers not involving hydraulic 

fracturing using Equation W-13 of this section: 

f

f

Es,n  Nwo * EFwo V f * T (Eq. W-13) 

Where: 

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purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 72 of 206

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Esa,n = Annual natural gas emissions in standard cubic 

feet at actual conditions from a gas well venting 

during well completions and workovers without 

hydraulic fracturing. 

Nwo = Number of workovers per field not involving 

hydraulic fracturing in the reporting year. 

EFwo = Emission Factor for non-hydraulic fracture well 

workover venting in actual standard cubic feet 

per workover. EFwo = 31142,454 standard cubic feet 

per well workover without hydraulic fracturing. 

f = Total number of well completions without 

hydraulic fracturing in a fieldsub-basin 

category. 

VfVp = Average daily gas production rate in standard 

cubic feet per hour of each well completion 

without hydraulic fracturing, p. This is the 

total annual gas production volume divided by 

total number of hours the wells produced to the 

sales line. For completed wells that have not 

established a production rate, you may use the 

average flow rate from the first 30 days of 

production. In the event that the well is 

completed less than 30 days from the end of the 

calendar year, the first 30 days of the 

production straddling the current and following 

calendar years shall be used. 

TfTp = Time each well completion without hydraulic 

fracturing, p, was venting in hours during the 

year. 

(1) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(12) Both CH4 and CO2 vVolumetric and mass emissions 

for both CH4 and CO2 shall be calculated from volumetric 

natural gas emissions using calculations in paragraphs (u) 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 73 of 206

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and (v) of this section. Mass emissions for both CH4 and CO2

shall be calculated from volumetric natural gas emissions 

using calculation in paragraphs (v) of this section.

(23) Calculate annual emissions from gas well venting 

during well completions and workovers not involving 

hydraulic fracturing to flares as follows: 

(i) Use the gas well venting volume during well 

completions and workovers as determined in paragraph (h) of 

this section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine gas well 

venting during well completions and workovers emissions 

without hydraulic fracturing from the flare. 

(i) Blowdown vent stacks. Calculate CO2 and CH4

blowdown vent stack emissions from depressurizing equipment 

to reduce system pressure for planned or emergency 

shutdowns or to take equipment out of service for 

maintenance the atmosphere (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 

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 74 of 206

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(e)(5) of this section) as follows (Emissions from 

emergency vents are not included.): 

(1) Calculate the total physical volume (including 

pipelines, compressor case or cylinders, manifolds, suction 

bottles, discharge bottles, and vessels) between isolation 

valves determined by engineering estimate based on best 

available data. 

(2) If the total physical volume between isolation 

valves is greater than or equal to 50 standard cubic feet, 

retain logs of the number of blowdowns for each equipment

unique physical volume type (including but not limited to 

compressors, vessels, pipelines, headers, fractionators, 

and tanks). Blowdown Physical volumes smaller than 50 

standard cubic feet are exempt from reporting under 

paragraph (i) of this section. 

(3) Calculate the total annual venting emissions for 

each equipment type using Equation W-14 of this section: 

 

  













 

















  V C

T P

T P

E N V v

a s

s a

s n v * 459.67

459.67 , * (Eq. W-14A) 

Where: 

Es,n = Annual natural gas venting emissions at standard 

conditions from blowdowns in cubic feet. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 75 of 206

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N = Number of repetitive blowdowns for each equipment 

type of a unique volume in calendar year. 

Vv = Total physical volume of blowdown equipment 

chambers (including pipelines, compressors and 

vessels) between isolation valves in cubic feet. 

C = Purge factor that is 1 if the equipment is not 

purged or zero if the equipment is purged using 

non-GHG gases. 

Ts = Temperature at standard conditions (o

F). 

Ta = Temperature at actual conditions in the blowdown 

equipment chamber (o

F). 

Ps = Absolute pressure at standard conditions (psia). 

Pa = Absolute pressure at actual conditions in the 

blowdown equipment chamber (psia).

  

   

































  

N

p a s

s a s p a e p

s n v T P

T P P

E V

1

, , , ,

, 459.67

459.67

 (Eq. W-14B)

Where:

Es,n = Annual natural gas venting emissions at standard 

conditions from blowdowns in cubic feet.

N = Number of repetitive blowdowns for each unique 

volume in calendar year.

Vv = Total volume of blowdown equipment chamber 

(including pipelines, compressors and vessels) 

between isolation valves in cubic feet for each 

blowdown “i.”

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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C = Purge factor that is 1 if the equipment is not 

purged or zero if the equipment is purged using 

non-GHG gases.

Ts = Temperature at standard conditions (oF).

Ta = Temperature at actual conditions in the blowdown 

equipment chamber (oF) for each blowdown “i”.

Ps = Absolute pressure at standard conditions (psia).

Pa,s,p = Absolute pressure at actual conditions in the 

blowdown equipment chamber (psia) at the start of

the blowdown “p”.

Pa,e,p = Absolute pressure at actual conditions in the 

blowdown equipment chamber (psia) at the end of 

the blowdown “p”; 0 if blowdown volume is purged 

using non-GHG gases.

(4) Calculate both CH4 and CO2 volumetric and mass 

emissions from volumetric natural gas emissions using 

calculations in paragraph (u) and(v) of this section. 

(5) Calculate total annual venting emissions for all 

blowdown vent stacks by adding all standard volumetric and 

mass emissions determined in Equation W-14A or W-14B and 

paragraph (i)(4) of this section. 

(j) Onshore production storage tanks. Calculate CH4, 

CO2 and N2O (when flared) emissions from atmospheric 

pressure fixed roof storage tanks receiving hydrocarbon 

produced liquids from onshore petroleum and natural gas 

production facilities (including stationary liquid storage 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 77 of 206

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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 

oilannual average daily throughput of oil greater than or 

equal to 10 barrels per day. Calculate annual CH4 and CO2

emissions from onshore production storage tanks using 

operating conditions in the last wellhead gas-liquid 

separator before liquid transfer to storage tanks. 

Calculate flashing emissions with a software program, such 

as AspenTech HYSYS® or API 4697 E&P Tank, that uses the 

Peng-Robinson equation of state, models flashing emissions, 

and speciates CH4 and CO2 emissions that will result when 

the oil from the separator enters an atmospheric pressure 

storage tank. A minimum of the following parameters 

determined for typical operating conditions over the year 

by engineering estimate and process knowledge based on best 

available data must be used to characterize emissions from 

liquid transferred to tanks. 

(i) Separator temperature. 

(ii) Separator pressure. 

(iii) Sales oil or stabilized oil API gravity. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(iv) Sales oil or stabilized oil production rate. 

(v) Ambient air temperature. 

(vi) Ambient air pressure. 

(vii) Separator oil composition and Reid vapor 

pressure. If this data is not available, determine these 

parameters by selecting one of the methods described under 

paragraph (j)(1)(viii) of this section. 

(A) If separator oil composition and Reid vapor 

pressure default data are provided with the software 

program, select the default values that most closely match 

your separator pressure first, and API gravity secondarily. 

(B) If separator oil composition and Reid vapor 

pressure data are available through your previous analysis, 

select the latest available analysis that is representative 

of produced crude oil or condensate from the fieldsub-basin 

category. 

(C) Analyze a representative sample of separator oil 

in each field subin-basin category for oil composition and 

Reid vapor pressure using an appropriate standard method 

published by a consensus-based standards organization. 

(2) Calculation Methodology 2. Calculate annual CH4

and CO2 emissions from onshore production storage tanks for 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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wellhead gas-liquid separators with annual average dailyoil

throughput of oil greater than or equal to 10 barrels per 

day by assuming that all of the CH4 and CO2 in solution at 

separator temperature and pressure is emitted from oil sent 

to storage tanks. You may use an appropriate standard 

method published by a consensus-based standards 

organization if such a method exists or you may use an 

industry standard practice as described in §98.234(b)(1) to 

sample and analyze separator oil composition at separator 

pressure and temperature. 

(3) Calculation Methodology 3. For wells with annual 

average daily oil production greater than or equal to 10 

barrels per day that flow directly to atmospheric storage 

tanks without passing through a wellhead separator, 

calculate annual CH4 and CO2 emissions by either of the 

methods in paragraph (j)(3) of this section: 

(i) If well production oil and gas compositions are 

available through your previous analysis, select the latest 

available analysis that is representative of produced oil 

and gas from the field sub-basin category and assume all of 

the CH4 and CO2 in both oil and gas are emitted from the 

tank. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(ii) If well production oil and gas compositions are 

not available, use default oil and gas compositions in 

software programs, such as API 4697 E&P Tank, that most 

closely match your well production gas/oil ratio and API 

gravity and assume all of the CH4 and CO2 in both oil and 

gas are emitted from the tank. 

(4) Calculation Methodology 4. For wells with annual 

average daily oil production greater than or equal to 10 

barrels per day that flow to a separator not at the well 

pad, calculate annual CH4 and CO2 emissions by either of the 

methods in paragraph (j)(4) of this section: 

(i) If well production oil and gas compositions are 

available through your previous analysis, select the latest 

available analysis that is representative of oil at 

separator pressure determined by best available data and 

assume all of the CH4 and CO2 in the oil is emitted from the 

tank. 

(ii) If well production oil composition is not 

available, use default oil composition in software 

programs, such as API 4697 E&P Tank, that most closely 

match your well production API gravity and pressure in the 

off-well pad separator determined by best available data. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Assume all of the CH4 and CO2 in the oil phase is emitted 

from the tank. 

(5) Calculation Methodology 5. For well pad gasliquid separators and for wells flowing off a well pad 

without passing through a gas-liquid separator with 

throughput less than 10 barrels per day use Equation W-15 

of this section: 

Es,i EFi *Count*1000 (Eq. W-15) 

Where: 

Es,i = Annual total volumetric GHG emissions (either 

CO2 or CH4) at standard conditions in cubic 

feet. 

EFi = Populations emission factor for separators 

orand wells in thousand standard cubic feet 

per separator or well per year, for crude oil 

use 4.3 for CH4 and 2.9 for CO2 at 68°F and 

14.7 psia, and for gas condensate use 17.8 for 

CH4 and 2.9 for CO2 at 68°F and 14.7 psia. 

Count = Total number of separators orand wells with 

throughput less than 10 barrels per day.

1000 = Conversion to cubic feet

(6) Determine if the storage tank receiving your 

separator oil has a vapor recovery system. 

(i) Adjust the emissions estimated in paragraphs 

(j)(1) through (j)(5) of this section downward by the 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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magnitude of emissions recovered using a vapor recovery 

system as determined by engineering estimate based on best 

available data. 

(ii) [Reserved] 

 (7) Determine if the storage tank receiving your 

separator oil is sent to flare(s). 

(i) Use your separator flash gas volume and gas 

composition as determined in this section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine your 

contribution to storage tank emissions from the flare. 

(8) Calculate emissions from occurrences of well pad 

gas-liquid separator liquid dump valves not closing during 

the calendar year by using Equation W-16 of this section. 

    n n n

n

s i n T E T E E CF    

 



  * * 8760

8760 , * (Eq. W-16) 

Where: 

Es,i = Annual total volumetric GHG emissions at 

standard conditions from each storage tank in 

cubic feet. 

En = Storage tank emissions as determined in 

Calculation Methodologies 1, 2, or 45 in 

paragraphs (j)(1), (j)(2) and through (j)(45) of 

this section (with wellhead separators) during 

time Tn in cubic feet per yearhour. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Tn = Total time the dump valve is not closing 

properly in the calendar year in hours. Tn is 

estimated by maintenance or operations records 

(records) such that when a record shows the 

valve to be open improperly, it is assumed the 

valve was open for the entire time period 

preceding the record starting at either the 

beginning of the calendar year or the previous 

record showing it closed properly within the 

calendar year. If a subsequent record shows it 

is closing properly, then assume from that time 

forward the valve closed properly until either 

the next record of it not closing properly or, 

if there is no subsequent record, the end of the 

calendar year. 

CFn = Correction factor for tank emissions for time 

period Tn is 3.87 for crude oil production. 

Correction factor for tank emissions for time 

period Tn is 5.37 for gas condensate production. 

Correction factor for tank emissions for time 

period Tn is 1.0 for periods when the dump valve 

is closed.

8,760 = Conversion to hourly emissions.

Et = Storage tank emissions as determined in 

Calculation Methodologies 1, 2, or 3 in 

paragraphs (j)(1) through (j)(5) of this section 

at maintenance or operations during the time the 

dump valve is closing properly (ie.8760-Tn) in 

cubic feet per hour. 

(9) Calculate both CH4 and CO2 mass emissions from 

volumetric natural gas emissions using calculations in 

paragraph (v) of this section. 

(k) Transmission storage tanks. For condensate 

storage tanks, either water or hydrocarbon, without vapor 

recovery or thermal control devices in onshore natural gas 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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transmission compression facilities calculate CH4, CO2 and 

N2O (when flared) annual emissions from compressor scrubber 

dump valve leakage as follows: 

(1) Monitor the tank vapor vent stack annually for 

emissions using an optical gas imaging instrument according 

to methods set forth in §98.234(a)(1) or by directly

measuring the tank vent using a flow meter, calibrated bag, 

or high volume sampler according to methods in §98.234(b) 

through (d) for a duration of 5 minutes.for a duration of 5 

minutes. Or you may annually monitor leakage through 

compressor scrubber dump valve(s) into the tank using an 

acoustic leak detection device according to methods set 

forth in §98.234(a)(5). 

(2) If the tank vapors 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: 

(i) Use a meter, such as a turbine meter, calibrated 

bag, or high flow sampler to estimate tank vapor volumes 

according to methods set forth in §98.234(b)through (d). 

If you do not have a continuous flow measurement device, 

you may install a flow measuring device on the tank vapor 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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vent stack. If the vent is directly measured for five 

minutes under paragraph §98.233(k)(1) of this section to 

detect continuous leakage, this serves as the measurement.

(ii) Use an acoustic leak detection device on each 

scrubber dump valve connected to the tank according to the 

method set forth in §98.234(a)(5). 

(iii) Use the appropriate gas composition in 

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

(3) If the leaking dump valve(s) is fixed following 

leak detection, the annual emissions shall be calculated 

from the beginning of the calendar year to the time the 

valve(s) is repaired. 

(4) Calculate annual emissions from storage tanks to 

flares as follows: 

(i) Use the storage tank emissions volume and gas 

composition as determined in either paragraph (j)(1)of this 

section or with an acoustic leak detection device in 

paragraphs (k)(1) through (k)(3) of this section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine storage tank 

emissions sent to afrom the flare. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(l) Well testing venting and flaring. Calculate CH4, 

CO2 and N2O (when flared) well testing venting and flaring 

emissions as follows: 

(1) Determine the gas to oil ratio (GOR) of the 

hydrocarbon production from each well tested. 

(2) If GOR cannot be determined from your available 

data, then you must measure quantities reported in this 

section according to one of the two procedures in 

paragraph (l)(2) of this section to determine GOR: 

(i) You may use an appropriate standard method 

published by a consensus-based standards organization if 

such a method exists. 

(ii) Or you may use an industry standard practice as 

described in §98.234(b). 

(3) Estimate venting emissions using Equation W-17 of 

this section. 

Ea,n  GOR *FR*D (Eq. W-17) 

Where: 

Ea,n = Annual volumetric natural gas emissions from well 

testing in cubic feet under actual conditions. 

GOR = Gas to oil ratio in cubic feet of gas per barrel 

of oil; oil here refers to hydrocarbon liquids 

produced of all API gravities. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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FR = Flow rate in barrels of oil per day for the well 

being tested. 

D = Number of days during the year, the well is 

tested. 

(4) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(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. 

(6) Calculate emissions from well testing to flares 

as follows: 

(i) Use the well testing emissions volume and gas 

composition as determined in paragraphs (l)(1) through (3) 

of this section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine well testing 

emissions from the flare. 

(m) Associated gas venting and flaring. Calculate 

CH4, CO2 and N2O (when flared) associated gas venting and 

flaring emissions not in conjunction with well testing 
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(refer to paragraph (l): Well testing venting and flaring 

of this section) as follows: 

(1) Determine the GOR of the hydrocarbon production 

from each well whose associated natural gas is vented or 

flared. If GOR from each well is not available, the GOR 

from a cluster of wells in the same field sub-basin 

category shall be used. 

(2) If GOR cannot be determined from your available 

data, then use one of the two procedures in paragraph 

(m)(2) of this section to determine GOR: 

(i) You may use an appropriate standard method 

published by a consensus-based standards organization if 

such a method exists. 

(ii) Or you may use an industry standard practice as 

described in §98.234(b). 

(3) Estimate venting emissions using Equation W-18 of 

this section. 

Ea,n  GOR*V (Eq. W-18) 

Where: 

Ea,n = Annual volumetric natural gas emissions from 

associated gas venting under actual conditions, 

in cubic feet. 

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effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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GOR = Gas to oil ratio in cubic feet of gas per barrel 

of oil; oil here refers to hydrocarbon liquids 

produced of all API gravities. 

V = Volume of oil produced in barrels in the calendar 

year during which associated gas was vented or 

flared. 

(4) Calculate natural gas volumetric emissions at 

standard conditions using calculations in paragraph (t) of 

this section. 

(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. 

(6) Calculate emissions from associated natural gas 

to flares as follows: 

(i) Use the associated natural gas volume and gas 

composition as determined in paragraph (m)(1) through (4) 

of this section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine associated 

gas emissions from the flare. 

(n) Flare stack emissions. Calculate CO2, CH4, and 

N2O emissions from a flare stack as follows: 

(1) If you have a continuous flow measurement device 

on the flare, you must use the measured flow volumes to 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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calculate the flare gas emissions. If all of the flare gas 

is not measured by the existing flow measurement device, 

then the flow not measured can be estimated using 

engineering calculations based on best available data or 

company records. If you do not have a continuous flow 

measurement device on the flare, you can install a flow 

measuring device on the flare or use engineering 

calculations based on process knowledge, company records, 

and best available data. 

(2) If you have a continuous gas composition analyzer 

on gas to the flare, you must use these compositions in 

calculating emissions. If you do not have a continuous gas 

composition analyzer on gas to the flare, you must use the 

appropriate gas compositions for each stream of 

hydrocarbons going to the flare as follows: 

(i) For onshore natural gas production, determine 

natural gas composition using (u)(2)(i) of this section. 

(ii) For onshore natural gas processing, when the 

stream going to flare is natural gas, use the GHG mole 

percent in feed natural gas for all streams upstream of the 

de-methanizer or dew point control, and GHG mole percent in 

facility specific residue gas to transmission pipeline 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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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.

(iii) For any applicable industry segment, wWhen the 

stream going to the flare is a hydrocarbon product stream, 

such as methane, ethane, propane, butane, pentane-plus and 

mixed light hydrocarbons, then you may use a representative 

composition from the source for the stream determined by 

engineering calculation based on process knowledge and best 

available data. 

(3) Determine flare combustion efficiency from 

manufacturer. If not available, assume that flare 

combustion efficiency is 98 percent. 

(4) Calculate GHG volumetric emissions at actual 

conditions using Equations W-19, W-20, and W-21 of this 

section. 

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

  , 2 2 * a CO Va XCO E uncombusted  (Eq. W-20) 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 92 of 206

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    



5

1

, 2 * * * Ja CO Va Yj Rj E combusted     

j

a CO Va Yj Rj E , 2 combusted  * * * (Eq. W-21) 

Where: 

Ea,CH4(un-combusted) = Contribution of annual un-combusted 

CH4 emissions from flare stack in 

cubic feet, under actual conditions. 

Ea,CO2(un-combusted) = Contribution of annual un-combusted 

CO2 emissions from flare stack in 

cubic feet, under actual conditions. 

Ea,CO2(combusted) = Contribution of annual combusted CO2

emissions from flare stack in cubic 

feet, under actual conditions. 

Va = Volume of gas sent to flare in cubic 

feet, during the year. 

η = Fraction of gas combusted by a 

burning flare (default is 0.98). For 

gas sent to an unlit flare, η is 

zero. 

XCH4 = Mole fraction of CH4 in gas to the 

flare. 

XCO2 = Mole fraction of CO2 in gas to the 

flare. 

Yj = Mole fraction of gas hydrocarbon 

constituents j (such as methane, 

ethane, propane, butane, and 

pentanes-plus). 

Rj = Number of carbon atoms in the gas 

hydrocarbon constituent j: 1 for 

methane, 2 for ethane, 3 for propane, 

4 for butane, and 5 for pentanes 

plus). 

Field Code Changed
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 93 of 206

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(5) Calculate GHG volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section. 

(6) Calculate both CH4 and CO2 mass emissions from 

volumetric CH4 and CO2 emissions using calculation in 

paragraph (v) of this section. 

(7) Calculate total annual emission from flare stacks 

by summing Equation W-40, Equation W-19, Equation W-20 and 

Equation W-21 of this section. 

(8) Calculate N2O emissions from flare stacks using 

Equation W-40 in paragraph (z) of this section. 

(9) The flare emissions determined under paragraph 

(n) of this section must be corrected for flare emissions 

calculated and reported under other paragraphs of this 

section to avoid double counting of these emissions. If you 

operate and maintain a CEMS that has both a CO2

concentration monitor and volumetric flow rate monitor, you 

must calculate CO2 emissions for the flare by following the 

Tier 4 Calculation Methodology and all associated 

calculation, quality assurance, reporting, and 

recordkeeping requirements for Tier 4 in subpart C of this 

part (General Stationary Fuel Combustion Sources). If a 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 94 of 206

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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).

(10) The flare emissions determined under paragraph 

(n) of this section must be corrected for flare emissions 

calculated and reported under other paragraphs of this 

section to avoid double counting of these emissions.

(11) If source types in §98.233 use Equations W-19 

through W-21 of this section, use estimate of emissions 

under actual conditions for the parameter, Va, in these 

equations.

(o) Centrifugal compressor venting. Calculate CH4, 

CO2 and N2O (when flared) emissions from both wet seal and 

dry seal centrifugal compressor vents as follows: 

(1) For each centrifugal compressor covered by 

§98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) you must 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 95 of 206

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conduct an annual measurement in the operating mode in 

which it is found. Measure emissions from all vents 

(including emissions manifolded to common vents) including 

wet seal oil degassing vents, unit isolation valve vents, 

and blowdown valve vents. Record emissions from the 

following vent types in the specified compressor modes 

during the annual measurement. 

(i) Operating mode, blowdown valve leakage through 

the blowdown vent, wet seal and dry seal compressors. 

(ii) Operating mode, wet seal oil degassing vents. 

(iii) Not operating, depressurized mode, unit 

isolation valve leakage through open blowdown vent, without 

blind flanges, wet seal and dry seal compressors. 

(A) For the not operating, depressurized mode, each 

compressor must be measured at least once in any three 

consecutive calendar years. If a compressor is not 

operated and has blind flanges in place throughout the 3 

year period, measurement is not required in this mode. If 

the compressor is in standby depressurized mode without 

blind flanges in place and is not operated throughout the 3 

year period, it must be measured in the standby 

depressurized mode. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 96 of 206

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(2) For wet seal oil degassing vents, determine vapor 

volumes sent to an atmospheric vent or flare, using a 

temporary meter such as a vane anemometer or permanent flow 

meter according to 98.234(b) of this section. If you do 

not have a permanent flow meter, you may install a 

permanent flow meter on the wet seal oil degassing tank 

vent. 

(3) For blowdown valve leakage and unit isolation 

valve leakage to open ended vents, you can use one of the 

following methods: calibrated bagging or high volume 

sampler according to methods set forth in §98.234(c) and 

§98.234(d), respectively. For through valve leakage, such 

as isolation valves, you may use an acoustic leak detection 

device according to methods set forth in §98.234(a). If 

you do not have a flow meter, you may install a port for 

insertion of a temporary meter, or a permanent flow meter, 

on the vents. 

(4) Estimate annual emissions using the flow 

measurement and Equation W-22 of this section. 

* * *(1 ) Es,i,m MTm Tm Mi,m Bm (Eq. W-22) 

Where: 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 97 of 206

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Es,i,m = Annual GHG i (either CH4 or CO2) volumetric 

emissions at standard conditions, in cubic feet. 

MTm = Measured gas emissions in standard cubic feet per 

hour. 

Tm = Total time the compressor is in the mode for 

which Es,i is being calculated, in the calendar 

year in hours. 

Mi,m = Mole fraction of GHG i in the vent gas; use the 

appropriate gas compositions in paragraph (u)(2) 

of this section. 

Bm = Fraction of operating time that the vent gas is 

sent to vapor recovery or fuel gas as determined 

by keeping logs of the number of operating hours 

for the vapor recovery system and the time that 

vent gas is directed to the fuel gas system or 

sales. 

(5) Calculate annual emissions from each centrifugal 

compressor using Equation W-23 of this section. 

 

m

EFm EFm Tm GHGi * * (Eq. W-23) 

Where: 

Es,i = Annual total volumetric GHG emissions at 

standard conditions from each centrifugal 

compressor in cubic feet. 

EFm = Reporter emission factor for each mode m, in 

cubic feet per hour, from Equation W-24 of this 

section as calculated in paragraph 6. 

Tm = Total time in hours per year the compressor was 

in each mode, as listed in paragraph (o)(1)(i) 

through (o)(1)(iii). 

GHGi = For onshore natural gas processing facilities, 

concentration of GHG i, CH4 or CO2, in produced 

natural gas or feed natural gas; for other 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 98 of 206

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facilities listed in §98.230(a)(4) through 

(a)(8),GHGi equals 1. 

(6) You shall use the flow measurements of operating 

mode wet seal oil degassing vent, operating mode blowdown 

valve vent and not operating depressurized mode isolation 

valve vent for all the reporter’s compressor modes not 

measured in the calendar year to develop the following 

emission factors using Equation W-24 of this section for 

each emission source and mode as listed in paragraph 

(o)(1)(i) through (o)(1)(iii). 

 m

m

m Count

MT

EF (Eq. W-24) 

Where: 

EFm = Reporter emission factors for compressor in the 

three modes m (as listed in paragraph (o)(1)(i) 

through (o)(1)(iii)) in cubic feet per hour. 

MTm = Flow Measurements from all centrifugal compressor 

vents in each mode in (o)(1)(i) through 

(o)(1)(iii) of this section in standard cubic 

feet per hour. 

Countm = Total number of compressors measured. 

m = Compressor mode as listed in paragraph (o)(1)(i) 

through (o)(1)(iii). 

 (i) The emission factors must be calculated 

annually. You must use all measurements from the current 

calendar year and the preceding two calendar years, 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 99 of 206

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totaling three consecutive calendar years of measurements 

in paragraph (o)(6) of this section. 

(ii) [Reserved] 

(7) Onshore petroleum and natural gas production 

shall calculate emissions from centrifugal compressor wet 

seal oil degassing vents as follows: 

Es,iCount*EFi (Eq. W-25) 

Where: 

Es,i = Annual total volumetric GHG emissions at 

standard conditions from centrifugal compressor 

wet seals in cubic feet. 

Count = Total number of centrifugal compressors for the 

reporter. 

EFi = Emission factor for GHG i. Use 12.2 million 

standard cubic feet per year per compressor for 

CH4 and 538 thousand standard cubic feet per year 

per compressor for CO2 at 68°F and 14.7 psia or 

12 million standard cubic feet per year per 

compressor for CH4 and 530 thousand standard 

cubic feet per year per compressor for CO2 at 

60°F and 14.7 psia. 

(8) Calculate both CH4 and CO2 mass emissions from 

volumetric emissions using calculations in paragraph (v) of 

this section. 

(9) Calculate emissions from seal oil degassing vent 

vapors to flares as follows: 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 100 of 206

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(i) Use the seal oil degassing vent vapor volume and 

gas composition as determined in paragraphs (o)(5) of this 

section. 

(ii) Use the calculation methodology of flare stacks 

in paragraph (n) of this section to determine degassing 

vent vapor emissions from the flare. 

(p) Reciprocating compressor venting. Calculate CH4

and CO2 emissions from all reciprocating compressor vents as 

follows. For each reciprocating compressor covered in 

§98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must 

conduct an annual measurement for each compressor in the 

mode in which it is found during the annual measurement, 

except as specified in paragraph (p)(9) of this section. 

Measure emissions from (including emissions manifolded to 

common vents) reciprocating rod packing vents, unit 

isolation valve vents, and blowdown valve vents. Record 

emissions from the following vent types in the specified 

compressor modes during the annual measurement as follows: 

(1) Operating or standby pressurized mode, blowdown 

vent leakage through the blowdown vent stack. 

(2) Operating mode, reciprocating rod packing 

emissions. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(3) Not operating, depressurized mode, unit isolation 

valve leakage through the blowdown vent stack, without 

blind flanges. 

(i) For the not operating, depressurized mode, each 

compressor must be measured at least once in any three 

consecutive calendar years if this mode is not found in the 

annual measurement. If a compressor is not operated and 

has blind flanges in place throughout the 3 year period, 

measurement is not required in this mode. If the 

compressor is in standby depressurized mode without blind 

flanges in place and is not operated throughout the 3 year 

period, it must be measured in the standby depressurized 

mode. 

(ii) [Reserved] 

(4) If reciprocating rod packing and blowdown vent 

are connected to an open-ended vent line use one of the 

following two methods to calculate emissions: 

(i) Measure emissions from all vents (including 

emissions manifolded to common vents) including rod 

packing, unit isolation valves, and blowdown vents using 

either calibrated bagging or high volume sampler according 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 102 of 206

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to methods set forth in §98.234 (c) and §98.234(d), 

respectively. 

(ii) Use a temporary meter such as a vane anemometer 

or a permanent meter such as an orifice meter to measure 

emissions from all vents (including emissions manifolded to 

a common vent) including rod packing vents and unit 

isolation valve leakage through blowdown vents according to 

methods set forth in §98.234(b). If you do not have a 

permanent flow meter, you may install a port for insertion 

of a temporary meter or a permanent flow meter on the 

vents. For through-valve leakage to open ended vents, such 

as unit isolation valves on not operating, depressurized 

compressors and blowdown valves on pressurized compressors, 

you may use an acoustic detection device according to 

methods set forth in §98.234(a). 

(5) If reciprocating rod packing is not equipped with 

a vent line use the following method to calculate 

emissions: 

(i) You must use the methods described in §98.234 (a) 

to conduct annual leak detection of equipment leaks from 

the packing case into an open distance piece, or from the 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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compressor crank case breather cap or other vent with a 

closed distance piece. 

(ii) Measure emissions found in paragraph (p)(5)(i) 

of this section using an appropriate meter, or calibrated 

bag, or high volume sampler according to methods set forth 

in §98.234(b), (c), and (d), respectively. 

(6) Estimate annual emissions using the flow 

measurement and Equation W-26 of this section. 

Es,i,m MTm Tm Mi,m  * * (Eq. W-26) 

Where: 

Es,i,m = Annual GHG i (either CH4 or CO2) volumetric 

emissions at standard conditions, in cubic feet. 

MTm = Measured gas emissions in standard cubic feet per 

hour. 

Tm = Total time the compressor is in the mode for 

which Es,i,m is being calculated, in the calendar 

year in hours. 

Mi,m = Mole fraction of GHG i in gas; use the 

appropriate gas compositions in paragraph (u)(2) 

of this section. 

(7) Calculate annual emissions from each 

reciprocating compressor using Equation W-27 of this 

section. 



m

Es i EFm Tm GHGi * * , (Eq. W-27) 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 104 of 206

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Where: 

Es,i = Annual total volumetric GHG emissions at 

standard conditions from each reciprocating 

compressor in cubic feet. 

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

cubic feet per hour, from Equation W-28 of this 

section as calculated in paragraph (p)(7)(i) of 

this section. 

Tm = Total time in hours per year the compressor was 

in each mode, m, as listed in paragraph (p)(1) 

through (p)(3). 

GHGi = For onshore natural gas processing facilities, 

concentration of GHG i, CH4 or CO2, in produced 

natural gas or feed natural gas; for other 

facilities listed in §98.230(a)(4) through 

(a)(8), GHGi equals 1. 

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

through (p)(3). 

(i) You shall use the flow meter readings from 

measurements of operating and standby pressurized blowdown 

vent, operating mode vents, not operating depressurized 

isolation valve vent for all the reporter’s compressor 

modes not measured in the calendar year to develop the 

following emission factors using Equation W-28 of this 

section for each mode as listed in paragraph (p)(1) through 

(p)(3). 

 m

m

m Count

MT EF (Eq. W-28) 
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Where: 

EFm = Reporter emission factors for compressor in the 

three modes, m, in cubic feet per hour. 

MTm = Meter readings from all reciprocating compressor 

vents in each and mode, m, in standard cubic feet 

per hour. 

Countm = Total number of compressors measured in each 

mode, m. 

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

through (p)(3). 

(A) You must combine emissions for blowndown vents, 

measured in the operating and standby pressurized modes. 

(B) The emission factors must be calculated annually. 

You must use all measurements from the current calendar 

year and the preceding two calendar years, totaling three 

consecutive calendar years of measurements. 

(ii) [Reserved] 

(8) Determine if the reciprocating compressor vent 

vapors are sent to a vapor recovery system. 

(i) Adjust the emissions estimated in paragraphs 

(p)(7) of this section downward by the magnitude of 

emissions recovered using a vapor recovery system as 

determined by engineering estimate based on best available 

data. 

(ii) [Reserved] 
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(9) Onshore petroleum and natural gas production 

shall calculate emissions from reciprocating compressors as 

follows: 

Es,iCount*EFi (Eq. W-29) 

Where: 

Es,i = Annual total volumetric GHG emissions at 

standard conditions from reciprocating 

compressors in cubic feet. 

Count = Total number of reciprocating compressors for 

the reporter. 

EFi = Emission factor for GHG i. Use 9.63 thousand 

standard cubic feet per year per compressor for 

CH4 and 0.535 thousand standard cubic feet per 

year per compressor for CO2 at 68°F and 14.7 psia 

or 9.48 thousand standard cubic feet per year 

per compressor for CH4 and 0.527 thousand 

standard cubic feet per year per compressor for 

CO2. at 60°F and 14.7 psia. 

(10) Estimate CH4 and CO2 volumetric and mass 

emissions from volumetric natural gas emissions using the 

calculations in paragraphs (u) and (v) of this section. 

(q) Leak detection and leaker emission factors. You 

must use the methods described in §98.234(a) to conduct 

leak detection(s) of equipment leaks from all sources 

listed in §98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), 

and (i)(1). This paragraph (q) applies to emissions 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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sources in 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 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 source per reporting facility using Equation 

W-30 of this section for each source with equipment leaks. 

  



x

p

Es i GHGi EF Tp

1

, * *  x

Es i GHGi EFs Tx * * , (Eq. W-30) 

Where: 

Es,i = Annual total volumetric GHG emissions at 

standard conditions from each equipment leak 

source in cubic feet. 

x = Total number of this type of emissions source 

found to be leaking during Txeach equipment leak 

source. 

EFs = Leaker emission factor for specific sources 

listed in Table W-2 through Table W-7 of this 

subpart. 

GHGi = For onshore natural gas processing facilities, 

concentration of GHGi, CH4 or CO2, in the total 

hydrocarbon of the feed natural gas; for other 

facilities listed in §98.230(a)(4) and 

(a)(5),GHGi equals 0.974 for CH4 and 1.0 × 10-2

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 108 of 206

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for CO2; for facilities listed in §98.230(a)(6) 

and (a)(7), GHGi equals 1 for CH4 and 0 for CO2; 

and for facilities listed in §98.230(a)(8), GHGi

equals 1 for CH4 and 1.1×10-2 CO2.through (a)(8), 

GHGi equals 1 for CH4 and 1.1 × 10-2 for CO2.

TxTp = The total time the component, p, was found 

leaking and operational, in hours. If one leak 

detection survey is conducted, assume the 

component was leaking for the entire calendar 

year. If multiple leak detection surveys are 

conducted, assume that the component found to be 

leaking has been leaking since the previous 

survey or the beginning of the entire calendar 

year. If multiple leak detection surveys are 

conducted, assume that the component found to be 

leaking has been leaking since the previous 

survey or the beginning of the calendar year.

For the last leak detection survey in the 

calendar year, assume that all leaking 

components continue to leak until the end of the 

calendar year. 

(1) You must select to conduct either one leak 

detection survey in a calendar year or multiple complete 

leak detection surveys in a calendar year. The number of 

leak detection surveys selected must be conducted during 

the calendar year. 

(2) Calculate GHG mass emissions in carbon dioxide 

equivalent at standard conditions using calculations in 

paragraph (v) of this section. 

(3) Onshore natural gas processing facilities shall 

use the appropriate default leaker emission factors listed 

in Table W-2 of this subpart for equipment leaks detected 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 109 of 206

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from valves, connectors, open ended lines, pressure relief 

valves, and meters. 

(4) Onshore natural gas transmission compression 

facilities shall use the appropriate default leaker 

emission factors listed in Table W-3 of this subpart for 

equipment leaks detected from valves, connectors, open 

ended lines, pressure relief valves, and meters. 

(5) Underground natural gas storage 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. 

(6) LNG storage facilities shall use the appropriate 

default leaker emission factors listed in Table W-5 of this 

subpart for equipment leaks detected from valves, pump 

seals, connectors, and other. 

(7) LNG import and export facilities shall use the 

appropriate default leaker emission factors listed in Table 

W-6 of this subpart for equipment leaks detected from 

valves, pump seals, connectors, and other. 

(8) Natural gas distribution facilities for above 

ground meters and regulators at city gate stations at Formatted: No underline, Font color: Auto,

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 110 of 206

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custody transfergrade transmission-distribution transfer 

stations, shall use the appropriate default leaker emission 

factors listed in Table W-7 of this subpart for equipment 

leak 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 transmission-distribution transfer 

stations. Below grade transmission-distribution transfer 

stations and metering-regulating stations that do not meet 

the definition of transmission-distribution transfer 

stations are not required to perform component leak 

detection under this section.

(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) and 

(i)(5), 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 or less than 

one half inch diameter are exempt from the requirements of 

paragraph (r) of this section and do not need to be 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 111 of 206

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reported. Calculate emissions from all sources listed in 

this paragraph using Equation W-31 of this section. 

Es,iCounts *EFs *GHGi *Ts (Eq. W-31) 

Where: 

Es,i = Annual volumetric GHG emissions at standard 

conditions from each equipment leak source in 

cubic feet. 

Counts = Total number of this type of emission source at 

the facility. For onshore petroleum and natural 

gas production, aAverage component counts are 

provided by major equipment piece in Tables W-1B 

and Table W-1C of this subpart. Use average 

component counts as appropriate for operations 

in Eastern and Western U.S., according to Table 

W-1D of this subpart. Underground natural gas 

storage shall count the components listed for 

population emission factors in Table W-4. LNG 

Storage shall count the number of vapor recovery 

compressors. LNG import and export shall count 

the number of vapor recovery compressors. 

Natural gas distribution shall count the 

respective component for each emission factor as 

described in paragraph (r)(6) of this section.

EFs = Population emission factor for the specific 

source, s listed in Table W-1A and Tables W-3 

through Table W-7 of this subpart. Use 

appropriate population emission factor for 

operations in Eastern and Western U.S., 

according to Table W-1D of this subpart. EF for 

meter/regulator runs at above grade meteringregulating stations is determined in Equation W32 of this section.EF for non-custody transfer 

city gate stations is determined in Equation W32.

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Comment [A1]: Ragan’s Comment: “make 

sure we truly mean facility” 

Response: The term facility has 

been removed.

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 112 of 206

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GHGi = For onshore petroleum and natural gas production 

facilities and onshore natural gas processing 

facilities, concentration of GHG i, CH4 or CO2, 

in produced natural gas or feed natural gas; for 

other facilities listed in §98.230(a)(4) through 

(a)(8),GHGi equals 1 for CH4 and 1.1 × 10-2 for 

CO2. 

Ts = Total time the specific source s associated with 

the equipment leak emission was operational in 

the calendar year, in hours. 

(1) Calculate both CH4 and CO2 mass emissions from 

volumetric emissions using calculations in paragraph (v) of 

this section. 

(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 

equipment and components associated with gas wells are 

considered gas service components in reference to Table 1-A 

of this subpart and major natural gas equipment in 

reference to Table W-1B of this subpart. Major equipment 

and components associated with crude oil wells are 

considered crude service components in reference to Table 

1-A of this subpart and major crude oil equipment in 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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reference to Table W-1C of this subpart. Where facilities 

conduct EOR operations the emissions factor listed in Table 

W-1A of this subpart shall be used to estimate all streams 

of gases, including recycle CO2 stream. The component count 

can be determined using either of the methodologies 

described in this paragraph (r)(2). The same methodology 

must be used for the entire calendar year. 

(i) Component Count Methodology 1. For all onshore 

petroleum and natural gas production operations in the 

facility perform the following activities: 

(A) Count all major equipment listed in Table W-1B 

and Table W-1C of this subpart. For meters/piping, use one 

meters/piping per well-pad.

(B) Multiply major equipment counts by the average 

component counts listed in Table W-1B and W-1C of this 

subpart for onshore natural gas production and onshore oil 

production, respectively. Use the appropriate factor in 

Table W-1A of this subpart for operations in Eastern and 

Western U.S. according to the mapping in Table W-1D of this 

subpart. 

(ii) Component Count Methodology 2. Count each 

component individually for the facility. Use the 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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appropriate factor in Table W-1A of this subpart for 

operations in Eastern and Western U.S. according to the 

mapping in Table W-1D of this subpart. 

(3) Underground natural gas storage facilities for 

storage wellheads shall use the appropriate default 

population emission factors listed in Table W-4 of this 

subpart for equipment leak from connectors, valves, 

pressure relief valves, and open ended lines. 

(4) LNG storage facilities shall use the appropriate 

default population emission factors listed in Table W-5 of 

this subpart for equipment leak from vapor recovery 

compressors. 

(5) LNG import and export facilities shall use the 

appropriate default population emission factor listed in 

Table W-6 of this subpart for equipment leak from vapor 

recovery compressors. 

(6) Natural gas distribution facilities shall use the 

appropriate emission factors as described in paragraph 

(r)(6) of this section. 

(i) Below grade metering-regulating stations 

(including below grade T-D transfer stations); distribution 

mains; and distribution services, shall use the appropriate 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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default population emission factors listed in Table W-7 of 

this subpart.Below grade meters and regulators; mains; and 

services, shall use the appropriate default population 

emission factors listed in Table W-7 of this subpart. 

(ii) Emissions from all above grade meteringregulating stations (including above grade TD transfer 

stations) shall be calculated by applying the emission 

factor calculated in Equation W-32 and the total count of 

meter/regulator runs at all above grade metering-regulating 

stations (inclusive of TD transfer stations) to Equation W31. 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 paragraph (q)(8) of this section and the 

count of meter/regulator runs located at above grade 

transmission-distribution transfer stations.Above grade 

meters and regulators at city gate stations not at custody 

transfer as listed in §98.232(i)(2), shall use the total 

volumetric GHG emissions at standard conditions for all

equipment leak sources calculated in paragraph (q)(8) of 

this section to develop facility emission factors using 

Equation W-32 of this section. The calculated facility 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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emission factor from Equation W-32 of this section shall be 

used in Equation W-31 of this section.

Count

E

EF s,i 8760   Count

E

EF s,i   (Eq. W-32) 

Where: 

EFiEF = Facility emission factor for a meter/regulator 

run at above grade metering-regulating for GHGi in 

cubic feet per meter/regulator run per hour.meter 

at above grade M&R at city gate stations not at 

custody transfer in cubic feet per meter per 

year.

Es,i = Annual volumetric GHGi emissions, CO2 or CH4 at 

standard condition from all equipment leak 

sources at all above grade M&R city gateTD 

transfer stations at custody transfer, from 

paragraph (q) of this section. 

Count = Total number of meter/regulator runs at all above 

grade M&R city gate stations at custody 

transfer.TD transfer stations.

8760 = Conversion to hourly emissions

(s) Offshore petroleum and natural gas production 

facilities. Report CO2, CH4, and N2O emissions for offshore 

petroleum and natural gas production from all equipment 

leaks, vented emission, and flare emission source types as 

identified in the data collection and emissions estimation 

study conducted by BOEMRE in compliance with 30 CFR 250.302 

through 304. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(1) Offshore production facilities under BOEMRE 

jurisdiction shall report the same annual emissions as 

calculated and reported by BOEMRE in data collection and 

emissions estimation study published by BOEMRE referenced 

in 30 CFR 250.302 through 304 (GOADS). 

(i) For any calendar year that does not overlap with 

the most recent BOEMRE emissions study publication year, 

report the most recent BOEMRE reported emissions data 

published by BOEMRE referenced in 30 CFR 250.302 through 

304 (GOADS). Adjust emissions based on the operating time 

for the facility relative to the operating time in the most 

recent BOEMRE published study. 

(ii) [Reserved] 

(2) Offshore production 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). 

(i) For any calendar year that does not overlap with 

the most recent BOEMRE emissions study publication, report 

the most recent reported emissions data with emissions 

adjusted based on the operating time for the facility 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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relative to operating time in the previous reporting 

period. 

(ii) [Reserved] 

(3) If BOEMRE discontinues or delays their data 

collection effort by more than 4 years, then offshore 

reporters shall once in every 4 years use the most recent 

BOEMRE data collection and emissions estimation methods to 

report emission from the facility sources. 

(4) For either first or subsequent year reporting, 

offshore facilities either within or outside of BOEMRE 

jurisdiction that were not covered in the previous BOEMRE 

data collection cycle shall use the most recent BOEMRE data 

collection and emissions estimation methods published by 

BOEMRE referenced in 30 CFR 250.302 through 304 to 

calculate and report emissions (GOADS) to report emissions. 

(t) Volumetric emissions. Calculate volumetric 

emissions at standard conditions as specified in paragraphs 

(t)(1) or (2) of this section, with actual pressure and 

temperature determined by engineering estimate based on 

best available data unless otherwise specified. 

(1) Calculate natural gas volumetric emissions at 

standard conditions by convertingusing actual natural gas 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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emission temperature and pressure of natural gas emissions 

to standard temperature and pressure, of natural gas 

usingand Equation W-33 of this section. 

 

  a s

a n s a

s n T P

E T P

E

459.67 *

, * 459.67 * , 

  (Eq. W-33) 

Where: 

Es,n = Natural gas volumetric emissions at standard 

temperature and pressure (STP) conditions in 

cubic feet. 

Ea,n = Natural gas volumetric emissions at actual 

conditions in cubic feet. 

Ts = Temperature at standard conditions (o

F). 

Ta = Temperature at actual emission conditions (o

F). 

Ps = Absolute pressure at standard conditions (psia). 

Pa = Absolute pressure at actual conditions (psia). 

(2) Calculate GHG volumetric emissions at standard 

conditions by converting using actual GHG emissions

temperature and pressure, and of GHG emissions to standard 

temperature and pressure using Equation W-34 of this 

section. 

 (Eq. W-34) 

Where: 

 

  a s

a i s a

s i

T P

E T P

E

459 .67 *

, * 459 .67 *

,



 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Es,i = GHG i volumetric emissions at standard 

temperature and pressure (STP) conditions in 

cubic feet. 

Ea,i = GHG i volumetric emissions at actual conditions 

in cubic feet. 

Ts = Temperature at standard conditions (oF). 

Ta = Temperature at actual emission conditions (o

F). 

Ps = Absolute pressure at standard conditions (psia). 

Pa = Absolute pressure at actual conditions (psia). 

(u) GHG volumetric emissions. Calculate GHG 

volumetric emissions at standard conditions as specified in 

paragraphs (u)(1) and (2) of this section, determined by 

engineering estimate based on best available data unless 

otherwise specified.with mole fraction of GHGs in the 

natural gas determined by engineering estimate based on 

best available data unless otherwise specified.

(1) Estimate CH4 and CO2 emissions from natural gas 

emissions using Equation W-35 of this section. 

 (Eq. W-35) 

Where: 

Es,i = GHG i (either CH4 or CO2) volumetric emissions at 

standard conditions in cubic feet. 

Es,n = Natural gas volumetric emissions at standard 

conditions in cubic feet. 

Es,i  Es,n * Mi

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Mi = Mole fraction of GHG i in the natural gas. 

(2) For Equation W-35 of this section, the mole 

fraction, Mi, shall be the annual average mole fraction for 

each sub-basin category or facility, as specified in 

paragraphs (u)(2)(i) through (vii) of this section. 

(i) GHG mole fraction in produced natural gas for 

onshore petroleum and natural gas production facilities. 

If you have a continuous gas composition analyzer for 

produced natural gas, you must use an annual average of

these values for determining the mole fraction. If you do 

not have a continuous gas composition analyzer, then you 

must use an annual average your most recent gas composition 

based on available sample analysis of the fieldsub-basin 

categories. 

(ii) GHG mole fraction in feed natural gas for all 

emissions sources 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 de-methanizer overhead 

or dew point control for onshore natural gas processing 

facilities. For onshore natural gas processing plants that 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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solely fractionate a liquid stream, use the GHG mole 

percent in feed natural gas liquid for all streams. If you 

have a continuous gas composition analyzer on feed natural 

gas, you must use these values for determining the mole 

fraction. If you do not have a continuous gas composition 

analyzer, then annual samples must be taken according to 

methods set forth in §98.234(b). 

(iii) GHG mole fraction in transmission pipeline 

natural gas that passes through the facility for onshore 

natural gas transmission compression facilities. You may 

use a default 95 percent methane and 1 percent carbon 

dioxide fraction for GHG mole fraction in natural gas.

(iv) GHG mole fraction in natural gas stored in 

underground natural gas storage facilities. You may use a 

default 95 percent methane and 1 percent carbon dioxide 

fraction for GHG mole fraction in natural gas. 

(v) GHG mole fraction in natural gas stored in LNG 

storage facilities. You may use a default 95 percent 

methane and 1 percent carbon dioxide fraction for GHG mole 

fraction in natural gas. 

(vi) GHG mole fraction in natural gas stored in LNG 

import and export facilities. For export facilities that 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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receive gas from transmission pipelines, you may use a 

default 95 percent methane and 1 percent carbon dioxide 

fraction for GHG mole fraction in natural gas.

(vii) GHG mole fraction in local distribution 

pipeline natural gas that passes through the facility for 

natural gas distribution facilities. You may use a default 

95 percent methane and 1 percent carbon dioxide fraction 

for GHG mole fraction in natural gas.

(v) GHG mass emissions. Calculate GHG mass emissions 

in carbon dioxide equivalent at standard conditions by 

converting the GHG volumetric emissions at standard 

conditions into mass emissions using Equation W-36 of this 

section. 

 (Eq. W-36) 

Where: 

Masss,i = GHG i (either CH4, or CO2, or N2O) mass 

emissions at standard conditions in metric tons 

CO2e. 

Es,i = GHG i (either CH4, or CO2, or N2O) volumetric 

emissions at standard conditions, in cubic feet. 

 = Density of GHG i. Use 0.05200538 kg/ft3 for CO2

and N2O, and 0.01900196 kg/ft3 for CH4 at 68°F 

and 14.7 psia or 0.0530 kg/ft3 for CO2 and N2O, 

and 0.0193 kg/ft3

 for CH4 at 60°F and 14.7 psia . 

3

, , * * * 10  Masss i  Es i  i GWP

 i  i

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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GWP = Global warming potential, 1 for CO2, 21 for CH4, 

and 310 for N2O. 

(w) EOR injection pump blowdown. Calculate CO2 pump 

blowdown emissions as follows: 

(1) Calculate the total volume in cubic feet 

(including pipelines, manifolds and vessels) between 

isolation valves. 

(2) Retain logs of the number of blowdowns per 

calendar year. 

(3) Calculate the total annual venting emissions 

using Equation W-37 of this section: 

3

, * * * *10 Massc i N Vv Rc GHGi (Eq. W-37) 

Where: 

Massc,i = Annual EOR injection gas venting emissions in 

metric tons at critical conditions “c” from 

blowdowns. 

N = Number of blowdowns for the equipment in the 

calendar year. 

Vv = Total volume in cubic feet of blowdown equipment 

chambers (including pipelines, manifolds and 

vessels) between isolation valves. 

Rc = Density of critical phase EOR injection gas in 

kg/ft3

. You may use an appropriate standard 

method published by a consensus-based standards 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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organization if such a method exists or you may 

use an industry standard practice to determine 

density of super critical EOR injection gas. 

GHGi = Mass fraction of GHGi in critical phase injection 

gas. 

1 × 10-3 = Conversion factor from kilograms to metric tons. 

(x) EOR hydrocarbon liquids dissolved CO2. Calculate 

dissolved CO2 in hydrocarbon liquids produced through EOR 

operations as follows: 

(1) Determine the amount of CO2 retained in 

hydrocarbon liquids after flashing in tankage at STP 

conditions. Annual samples must be taken according to 

methods set forth in §98.234(b) to determine retention of 

CO2 in hydrocarbon liquids immediately downstream of the 

storage tank. Use the annual analysis for the calendar 

year. 

(2) Estimate emissions using Equation W-38 of this 

section. 

 Masss,CO2 = Shl * Vhl (Eq. W-38) 

Where: 

Masss,CO2 = Annual CO2 emissions from CO2 retained in 

hydrocarbon liquids produced through EOR 

operations beyond tankage, in metric tons. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Shl = Amount of CO2 retained in hydrocarbon liquids 

in metric tons per barrel, under standard 

conditions. 

Vhl = Total volume of hydrocarbon liquids produced 

at the EOR operations in barrels in the 

calendar year. 

(y) [Reserved] 

(z) Onshore petroleum and natural gas production and 

natural gas distribution combustion emissions. Calculate 

CO2 CH4, and N2O combustion-related emissions from 

stationary or portable equipment, except as specified in 

paragraph (z)(3) of this section, as follows: 

(1) If the fuel combusted in the stationary or 

portable equipment is listed in Table C-1 of subpart C of 

this part, or is a blend of containing one or more fuels 

listed in Table C-1, use the Tier 1 methodology described 

in subpart C of this part (General Stationary Fuel 

Combustion Sources)calculate emissions according to 

(z)(1)(i). If the fuel combusted is natural gas and is of

pipeline quality specification and has a minimum high heat 

value of 950 Btu per standard cubic foot, use the 

calculation methodology described in (z)(1)(i) and you may 

used the then the natural gas emission factor provided for 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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natural gas as and high heat values listed in Tables C-1.

and C-2 of this part may be used. If the fuel is natural 

gas, and is not pipeline quality or has a high heat value 

of less than 950 Btu per standard cubic feet, calculate 

emissions according to (z)(2). If the fuel is field gas, 

process vent gas, or blend containing field gas or process 

vent gas, calculate emissions according to (z)(2).

(i) For fuels listed in Table C-1 or a blend 

containing one more fuels listed in Table C-1, calculate 

CO2, CH4, and N2O emissions according to any Tier listed in 

subpart C of this part. You must follow all applicable 

calculation requirements for that tier listed in 98.33, any 

monitoring or QA/QC requirements listed for that tier in 

98.34, any missing data procedures specified in 98.35, and 

any recordkeeping requirements specified in 98.37.

(ii) Emissions from fuel combusted in stationary or 

portable equipment at onshore natural gas and petroleum 

production facilities and at natural gas distribution 

facilities will be reported according to the requirements 

specified in 98.236(c)(19) and not according to the 

reporting requirements specified in subpart C of this part.

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(2) For fuel combustion units that combust field gas 

or process vent gas, or anya blend of containing field gas 

or process vent gas, or natural gas that is not of pipeline 

quality or that has a high heat value of less than 950 Btu 

per standard cubic feet, and fuels listed in Table C-1 of 

subpart C of this part, calculate combustion emissions as 

follows: 

(i) If you have a continuous flow meter on the 

combustion unit, you must use the measured flow volumes to 

calculate the total flow of gas to the unit. If you do not 

have a permanent flow meter on the combustion unit, you may 

install a permanent flow meter on the combustion unit, or 

use company records or engineering calculations based on 

best available data on heat duty or horsepower to estimate 

volumetric unit gas flow.You may use company records to 

determine the volume of fuel combusted in the unit during 

the reporting year. 

(ii) If you have a continuous gas composition 

analyzer on fuel to the combustion unit, you must use these 

compositions for determining the concentration of gas 

hydrocarbon constituent in the flow of gas to the unit. If 

you do not have a continuous gas composition analyzer on 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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gas to the combustion unit, you must use the appropriate 

gas compositions for each stream of hydrocarbons going to 

the combustion unit as specified in paragraph (u)(2)(i) of 

this section. 

(iii) Calculate GHG volumetric emissions at actual 

conditions using Equations W-39 of this section. 

  

j

Ea,CO2 Va *YCO2 * Va *Yj * Rj (Eq. W-39A)

, 4 * 4 *(1 ) Ea CH Va  YCH (Eq. W-39B)

Where: 

Ea,CO2 = Contribution of annual emissions from portable 

or stationary fuel combustion sources in cubic 

feet, under actual conditions.

Ea,CH4 = Contribution of annual CH4 emissions from 

portable or stationary fuel combustion sources 

in cubic feet, under actual conditions.

 = Combustion efficiency for portable and 

stationary equipment determined based on 

engineering estimation.

Va = Volume of gas sent to combustion unit in cubic 

feet, during the year. 

Yj = Concentration of gas hydrocarbon constituents 

j (such as methane, ethane, propane, butane, 

and pentanes plus)in gas sent to combustion 

unit.

YCH4 = Concentration of methane constituent in gas 

sent to combustion unit.

YCO2 = Concentration of CO2 constituent in gas sent 

to combustion unit.

Field Code Changed
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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N O     Fuel  HHV  EF 3

2 1 10

Rj = Number of carbon atoms in the gas hydrocarbon 

constituent j; 1 for methane, 2 for ethane, 3 

for propane, 4 for butane, and 5 for pentanes 

plus) in gas sent to combustion unit. 

(3) External fuel combustion sources with a rated 

heat capacity equal to or less than 5 mmBtu/hr do not need 

to report combustion emissions. You must report the type 

and number of each external fuel combustion unit.

(iv4) Calculate GHG volumetric emissions at standard 

conditions using calculations in paragraph (t) of this 

section. 

(v5) Calculate both combustion-related CH4 and CO2

mass emissions from volumetric CH4 and CO2 emissions using 

calculation in paragraph (v) of this section. 

(vi6) Calculate N2O mass emissions using Equation W-40 

of this section. 

(Eq. W-40)

N O  x xFuelxHHVxEFxGWP 3

2  1 10 (Eq. W-40)

Where: 

N2O = Annual N2O emissions from the combustion of a 

particular type of fuel (metric tons). 

Fuel = Mass or volume of the fuel combusted (mass 

or volume per year, choose appropriately to 

be consistent with the units of HHV). 

Field Code Changed
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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HHV = For the high heat value for field gas or 

process vent gas, use 1.235 x 10-3 mmBtu/scf 

for HHV.High heat value of the fuel from 

paragraphs (z)(8)(i),(z)(8)(ii) or 

(z)(8)(iii) of this section (units must be 

consistent with Fuel).

EF = Use 1.0 × 10-4 kg N2O/mmBtu. 

1 × 10-3 = Conversion factor from kilograms to metric 

tons.

GWP = Global warming potential, as listed in Table 

A-1 of subpart A of this part.

(i) For fuels listed in Table C-1 of subpart C of 

this part, use the provided default HHV in the table.

(ii) For field gas or process vent gas, use 1.235 ×

10-3 mmBtu/scf for HHV.

(iii) For fuels not listed in Table C-1 of subpart C 

of this part and not field gas or process vent gas, you 

must use the methodology set forth in the Tier 2 

methodology described in subpart C of this part to 

determine HHV.

(3) External fuel combustion sources with a rated heat 

capacity equal to or less than 5 mmBtu/hr do not need to 

report combustion emissions or include these emissions for 

threshold determination in §98.231(a). You must report the 

type and number of each external fuel combustion unit.
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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§98.234 Monitoring and QA/QC requirements.

The GHG emissions data for petroleum and natural gas 

emissions sources must be quality assured as applicable as 

specified in this section. Offshore petroleum and natural 

gas production facilities shall adhere to the monitoring 

and QA/QC requirements as set forth in 30 CFR 250. 

(a) You must use any of the methods described as 

follows in this paragraph to conduct leak detection(s) of 

equipment leaks and through-valve leakage from all source 

types listed in §98.233(k), (o), (p) and (q) that occur 

during a calendar year, except as provided in paragraph 

(a)(4) of this section. 

(1) Optical gas imaging instrument. Use an optical 

gas imaging instrument for equipment leak detection in 

accordance with 40 CFR part 60, subpart A, §60.18(i)(1) of 

the Alternative work practice for monitoring equipment 

leaks , §60.18(i)(1)(i); §60.18(i)(2)(i)(A) and (B) except 

that the monitoring frequency is annually using the 

detection sensitivity level of 60 grams per hour in Table 1 

to Subpart A to Part 60- Detection Sensitivity Levels; 

§60.18(i)(2)(ii) and (iii) except the gas chosen shall be 

methane, and (iv), and (v); §60.18(i)(3) and (4)(i) and (v) 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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The daily instrument check and distances, excluding any 

video records.and (2) of the Alternative work practice for 

monitoring equipment leaks. Any emissions detected by the 

optical gas imaging instrument is a leak unless screened 

with Method 21 (40 CFR part 60, appendix A-7) monitoring, 

in which case 10,000 ppm or greater is designated a leak. 

In addition, you must operate the optical gas imaging 

instrument to image the source types required by this 

subpart in accordance with the instrument manufacturer’s 

operating parameters. An optical gas imaging instrument 

must be used for all source types that are inaccessible and 

cannot be monitored without elevating the monitoring 

personnel more than 2 meters above a support surface.

(2) Method 21. Use the equipment leak detection 

methods in 40 CFR part 60, appendix A-7, Method 21. If 

using Method 21 monitoring, if an instrument reading of 

10,000 ppm or greater is measured, a leak is detected. 

Inaccessible emissions sources, as defined in 40 CFR part 

60, are not exempt from this subpart. Owners or operators 

must use alternative leak detection devices as described in 

paragraph(a)(1) or (a)(2) of this section to monitor 

inaccessible equipment leaks or vented emissions. 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(3) Infrared laser beam illuminated instrument. Use 

an infrared laser beam illuminated instrument for equipment 

leak detection. Any emissions detected by the infrared 

laser beam illuminated instrument is a leak unless screened 

with Method 21 monitoring, in which case 10,000 ppm or 

greater is designated a leak. In addition, you must 

operate the infrared laser beam illuminated instrument to 

detect the source types required by this subpart in 

accordance with the instrument manufacturer’s operating 

parameters. 

(4) [Reserved]Optical gas imaging instrument. An 

optical gas imaging instrument must be used for all source 

types that are inaccessible and cannot be monitored without 

elevating the monitoring personnel more than 2 meters above 

a support surface.

(5) Acoustic leak detection device. Use the acoustic 

leak detection device to detect through-valve leakage. 

When using the acoustic leak detection device to quantify 

the through-valve leakage, you must use the instrument 

manufacturer’s calculation methods to quantify the throughvalve leak. When using the acoustic leak detection device, 

if a leak of 3.1 scf per hour or greater is calculated, a 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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leak is detected. In addition, you must operate the 

acoustic leak detection device to monitor the source valves 

required by this subpart in accordance with the instrument 

manufacturer’s operating parameters. . Acoustic 

stethoscope type devices designed todetect through valve 

leakage when put in contact with the valve body and that 

provide an audible leak signal but do not calculate a leak 

rate can be used to identify non-leakers with subsequent 

measurement required to calculate the rate if through-valve 

leakage is identified. Leaks are reported if a leak rate 

of 3.1 scf per hour or greater is measured.

(b) You must operate and calibrate all flow meters, 

composition analyzers and pressure gauges used to measure 

quantities reported in §98.233 according to the procedures 

in §98.3(i) and the procedures in paragraph (b) of this 

section. You may use an appropriate standard method 

published by a consensus-based standards organization if 

such a method exists or you may use an industry standard 

practice. Consensus-based standards organizations include, 

but are not limited to, the following: ASTM International, 

the American National Standards Institute (ANSI), the 

American Gas Association (AGA), the American Society of 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Mechanical Engineers (ASME), the American Petroleum 

Institute (API), and the North American Energy Standards 

Board (NAESB). 

(c) Use calibrated bags (also known as vent bags) 

only where the emissions are at near-atmospheric pressures 

such that it is safe to handle and can capture all the 

emissions, and below the maximum temperature specified by 

the vent bag manufacturer such that the bag is safe to 

handle., The bag must be of sufficient size that and the 

entire emissions volume can be encompassed for measurement. 

(1) Hold the bag in place enclosing the emissions 

source to capture the entire emissions and record the time 

required for completely filling the bag. If the bag 

inflates in less than one second, assume one second 

inflation time. 

(2) Perform three measurements of the time required 

to fill the bag, report the emissions as the average of the 

three readings. 

(3) Estimate natural gas volumetric emissions at 

standard conditions using calculations in §98.233(t). 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(4) Estimate CH4 and CO2 volumetric and mass emissions 

from volumetric natural gas emissions using the 

calculations in §98.233(u) and (v). 

(d) Use a high volume sampler to measure emissions 

within the capacity of the instrument. 

(1) A technician following manufacturer instructions 

shall conduct measurements, including equipment 

manufacturer operating procedures and measurement 

methodologies relevant to using a high volume sampler, 

including positioning the instrument for complete capture 

of the equipment leak without creating backpressure on the 

source. 

(2) If the high volume sampler, along with all 

attachments available from the manufacturer, is not able to 

capture all the emissions from the source then use antistatic wraps or other aids to capture all emissions without 

violating operating requirements as provided in the 

instrument manufacturer’s manual. 

(3) Estimate natural gas volumetric emissions at 

standard conditions using calculations in §98.233(t). 

Estimate CH4 and CO2 volumetric and mass emissions from 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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volumetric natural gas emissions using the calculations in 

§98.233(u) and (v). 

(4) Calibrate the instrument at 2.5 percent methane 

with 97.5 percent air and 100 percent CH4 by using 

calibrated gas samples and by following manufacturer’s 

instructions for calibration. 

(e) Peng Robinson Equation of State means the 

equation of state defined by Equation W-41 of this section: 

2 2 V 2bV b

a

V b

RT

p

m m  m     

 (Eq. W-41) 

Where: 

p = Absolute pressure. 

R = Universal gas constant. 

T = Absolute temperature. 

Vm = Molar volume. 

a = c

c

p

R T

2 2 0.45724

b = c

c

p

0.7780RT

α =   2

2 1 0.37464 1.54226 0.26992 1 































    Tc

T  

Where: 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 139 of 206

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ω = Acentric factor of the species. 

Tc = Critical temperature. 

Pc = Critical pressure. 

(f) Special reporting provisions 

(1) Best available monitoring methods. EPA will 

allow owners or operators to use best available monitoring 

methods for parameters in §98.233 Calculating GHG Emissions 

as specified in paragraphs (f)(2), (f)(3), and (f)(4) of 

this section. If the reporter anticipates the potential 

need for best available monitoring for sources for which 

they need to petition EPA and the situation is unresolved 

at the time of the deadline, reporters should submit 

written notice of this potential situation to EPA by the 

specified deadline for requests to be considered. EPA 

reserves the right to review petitions after the deadline 

but will only consider and approve late petitions which 

demonstrate extreme or unusual circumstances. The 

Administrator reserves to right to request further 

information in regard to all petition requests. The owner 

or operator must use the calculation methodologies and 

equations in §98.233 Calculating GHG Emissions. Best 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 140 of 206

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available monitoring methods means any of the following 

methods specified in paragraph (f)(1) of this section: 

(i) Monitoring methods currently used by the facility 

that do not meet the specifications of this subpart. 

(ii) Supplier data. 

(iii) Engineering calculations. 

(iv) Other company records. 

(2) Best available monitoring methods for wellrelated emissions. During January 1, 2011 through June 

30December 31, 2011, owners or and operators may use best 

available monitoring methods for any well-related data that 

cannot reasonably be measured according to the monitoring 

and QA/QC requirements of this subpart, and only where 

required measurements cannot be duplicated due to technical 

limitations after June 30, 2011. These well-related 

sources are: 

(i) Gas well venting during well completions and 

workovers with hydraulic fracturing as specified in 

§98.233(g). 

(ii) Well testing venting and flaring as specified in 

§98.233(l). 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 141 of 206

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(3) Best available monitoring methods for specified 

activity data. During January 1, 2011 through June 

30December 31, 2011, owners or and operators may use best 

available monitoring methods for activity data as listed 

below that cannot reasonably be obtained according to the 

monitoring and QA/QC requirements of this subpart, 

specifically for events that generate data that can be 

collected only between January 1, 2011 and June 30, 2011 

and cannot be duplicated after June 30, 2011. These 

sources are: 

(i) Cumulative hours of venting, days, or times of 

operation in §98.233(e), (f), (g), (h), (l), (o), (p), (q), 

and (r). 

(ii) Number of blowdowns, completions, workovers, or 

other events in §98.233(f), (g), (h), (i), and (w). 

(iii) Cumulative volume produced, volume input or 

output, or volume of fuel used in paragraphs §98.233(d), 

(e), (j), (k), (l), (m), (n), (x), (y), and (z). 

(4) Best available monitoring methods for leak 

detection and measurement. The owner or operator may 

request use of best available monitoring methods 

betweenDuring January 1, 2011 throughand December 31, 2011,

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 142 of 206

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for sources requiring leak detection and/or 

measurementowners or operators may used best available 

monitoring methods for sources requiring leak detection 

and/or measurement. These sources include: 

(i) Reciprocating compressor rod packing venting in 

onshore natural gas processing, onshore natural gas 

transmission compression, underground natural gas storage, 

LNG storage, and LNG import and export equipment as 

specified in §98.232 (d)(1), (e)(1), (f)(1), (g)(1), and 

(h)(1). 

(ii) Centrifugal compressor wet seal oil degassing 

venting in onshore natural gas processing, onshore natural 

gas transmission compression, underground natural gas 

storage, LNG storage, and LNG import and export equipment 

as specified in §98.232(d)(2), (e)(2), (f)(2), (g)(2), and 

(h)(2). 

(iii) Acid gas removal vent stacks in onshore 

petroleum and natural gas production and onshore natural 

gas processing as specified in §98.232(c)(17) and (d)(6). 

(iv) Equipment leak emissions from valves, 

connectors, open ended lines, pressure relief valves, block 

valves, control valves, compressor blowdown valves, orifice 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 143 of 206

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meters, other meters, regulators, vapor recovery 

compressors, centrifugal compressor dry seals, and/or other 

equipment leaks in onshore natural gas processing, onshore 

natural gas transmission compression, underground natural 

gas storage, LNG storage, LNG import and export equipment, 

and natural gas distribution as specified in §98.232 

(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). 

(v) Condensate (oil and/or water) storage tanks in 

onshore natural gas transmission compression as specified 

in §98.232(e)(3). 

(5) Requests for the use of best available monitoring 

methods. The owner or operator may submit a request to the 

Administrator to use one or more best available monitoring 

methods. 

(i) No request or approval by the Administrator is 

necessary to use best available monitoring methods between 

January 1, 2011 and June 30December 31, 2011 for the 

sources specified in paragraph (f)(2) of this section. 

(ii) No request or approval by the Administrator is 

necessary to use best available monitoring methods between 

January 1, 2011 and June 30December 31, 2011 for the

sources specified in paragraph (f)(3) of this section. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 144 of 206

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(iii) Owners or operators must submit a request and 

receive approvalNo request or approval by the Administrator 

to is necessary to use best available monitoring methods 

between January 1, 2011 and December 31, 2011 for sources 

specified in paragraph (f)(4) of this section.

(iv) No request or approval by the Administrator is 

necessary to use best available monitoring methods between 

January 1, 2011 and December 31, 2011 for sources not 

listed in paragraph (f)(2), (f)(3), and (f)(4) of this 

section.

(A) Timing of request. The request to use best 

available monitoring methods for paragraph (f)(4) of this 

section must be submitted to EPA no later than April 30, 

2011. 

(B) Content of request. Requests must contain the 

following information for sources listed in paragraph 

(f)(4) of this section: 

(1) A list of specific source types and specific 

equipment, monitoring instrumentation, and/or services for 

which the request is being made and the locations where 

each piece of monitoring instrumentation will be installed 

or monitoring service will be supplied. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 145 of 206

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(2) Identification of the specific rule requirements 

(by subpart, section, and paragraph number) for which the 

instrumentation or monitoring service is needed. 

(3) Documentation which demonstrates that the owner 

or operator made all reasonable efforts to obtain the 

information, services or equipment necessary to comply with 

subpart W reporting requirements, including evidence of 

specific service or equipment providers contacted and why 

services or information could not be obtained during 2011. 

(4) A description of the specific actions the 

facility will take to obtain and/or install the equipment 

or obtain the monitoring service as soon as reasonably 

feasible and the expected date by which the equipment will 

be obtained and operating or service will be provided. 

(C) Approval criteria. To obtain approval, the owner 

or operator must demonstrate to the Administrator’s 

satisfaction that it does not own the required monitoring 

equipment, and it is not reasonably feasible to acquire, 

install, and operate a required piece of monitoring 

equipment or to obtain leak detection or measurement 

services in order to meet the requirements of this subpart 

for 2011. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 146 of 206

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(iv) EPA does not anticipate a need to approve the use 

of best available monitoring methods for sources not listed 

in paragraphs(f)(2), (f)(3), and (f)(4) of this section; 

however, EPA will review such requests if submitted in 

accordance with paragraph (f)(5)(iv)(A)-(C) of this 

section. 

(A) Timing of request. The request to use best 

available monitoring methods for sources not listed in 

paragraphs (f)(2), (f)(3), and (f)(4) of this section must 

be submitted to EPA no later than April 30, 2011. 

(B) Content of request. Requests must contain the 

following information: 

(1) A list of specific source categories and 

parameters for which the owner or operator is seeking use 

of best available monitoring methods. 

(2) A description of the data collection 

methodologies that do not meet safety regulations, 

technical infeasibility, or specific laws or regulations 

that conflict with each specific source for which an owner 

or operator is requesting use of best available monitoring 

methodologies. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 147 of 206

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(3) A detailed explanation and supporting 

documentation of how and when the owner or operator will 

receive the services or equipment to comply with all 

subpart W reporting requirements. 

(C) Approval criteria. To obtain approval, the owner 

or operator must demonstrate to the Administrator’s 

satisfaction that the owner or operator faces unique 

safety, technical or legal issues rendering them unable to 

meet the requirements of this subpart for 2011. 

(6) Requests for extension of the use of best 

available monitoring methods through December 31, 2011 for 

sources in paragraph (f)(2) of this section. The owner or 

operator may submit a request to the Administrator to use 

one or more best available monitoring methods described in 

paragraph (f)(2) of this section beyond June 30, 

2011.[Reserved] 

(i) Timing of request. The extension request must be 

submitted to EPA no later than April 30, 2011. 

(ii) Content of request. Requests must contain the 

following information: 

(A) A list of specific source types and specific 

equipment, monitoring instrumentation, contract 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 148 of 206

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modifications, and/or services for which the request is 

being made and the locations where each piece of monitoring 

instrumentation will be installed, monitoring service will 

be supplied, or contracts will be modified. 

(B) Identification of the specific rule requirements 

(by subpart, section, and paragraph number) for which the 

instrumentation, contract modification, or monitoring 

service is needed. 

(C) A description and applicable correspondence 

outlining the diligent efforts of the owner or operator in 

obtaining the needed equipment or service and why they 

could not be obtained and installed in a period of time 

enabling completion of applicable requirements of this 

subpart within the 2011 calendar year. 

(D) If the reason for the extension is that the owner 

or operator cannot collect data from a service provider or 

relevant organization in order for the owner or operator to 

meet requirements of this subpart for the 2011 calendar 

year, the owner or operator must demonstrate a good faith 

effort that it is not possible to obtain the necessary 

information, service or hardware which may include 

providing correspondence from specific service providers or 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 149 of 206

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other relevant entities to the owner or operator, whereby 

the service provider states that it is unable to provide 

the necessary data or services requested by the owner or 

operator that would enable the owner or operator to comply 

with subpart W reporting requirements by June 30, 2011. 

(E) A description of the specific actions the owner 

or operator will take to comply with monitoring 

requirements in 2012 and beyond. 

(iii) Approval criteria. To obtain approval, the 

owner or operator must demonstrate to the Administrator’s 

satisfaction that it is not reasonably feasible to obtain 

the data necessary to meet the requirements of this subpart 

for the sources specified in paragraph (f)(2) of this 

section by June 30, 2011. 

(7) Requests for extension of the use of best 

available monitoring methods through December 31, 2011 for 

sources in paragraph (f)(3) of this section. The owner or 

operator may submit a request to the Administrator to use 

one or more best available monitoring methods described in 

paragraph (f)(3) of this section beyond June 30, 

2011.[Reserved] 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(i) Timing of request. The extension request must be 

submitted to EPA no later than April 30, 2011. 

(ii) Content of request. Requests must contain the 

following information: 

(A) A list of specific source types for which data 

collection could not be implemented. 

(B) Identification of the specific rule requirements 

(by subpart, section, and paragraph number) for which the 

data collection could not be implemented. 

(C) A description of the data collection 

methodologies that do not meet safety regulations, 

technical infeasibility, or specific laws or regulations 

that conflict with each specific source for which an owner 

or operator is requesting use of best available monitoring 

methodologies for which data collection could not be 

implemented in the 2011 calendar year. 

(iii) Approval criteria. To obtain approval, the 

owner or operator must demonstrate to the Administrator’s 

satisfaction that it is not reasonably feasible to 

implement the data collection for the sources described in 

paragraph (f)(3) of this section for the methods required 

in this subpart by June, 30, 2011. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 151 of 206

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(8) Requests for extension of the use of best 

available monitoring methods beyond 2011 for sources listed 

in paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this 

section and other sources in this subpart. The owner or 

operator must first provide the Administrator an initial 

electronic notification of intent to submit an extension 

request for EPA does not anticipate a need for approving 

the use of best available methods beyond December 31, 2011

for unique or , except in extremeunusual circumstances 

which include data collection methods that do not meet 

safety regulations, a requirement being technically 

infeasible, or counter to other local, State, or Federal 

regulations. The owner or operator must follow-up this 

initial notification with an extension request containing 

the information specified in 98.234(f)(8)(ii). Facilities 

that submit both a timely notice of intent and extension 

request consistent with 98.234(f)(8)(ii) can automatically 

use BAMM through June 30, 2012, for the specific parameters 

identified in their notification of intent and BAMM request 

regardless of whether the BAMM request is ultimately 

approved. Facilities that submit a notice of intent but do 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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not follow up with a BAMM request by March 30, 2012 cannot 

automatically use BAMM after December 31, 2011.

circumstances, which include safety, a requirement 

being technically infeasible or counter to other local, 

State, or Federal regulations. 

(i) Timing of request. The initial electronic notice 

of intent to request BAMM must be submitted by December 31, 

2011. The completed extension request must be submitted to 

the Administrator no later than March 30, 2012. The request 

to use best available monitoring methods for paragraphs 

(f)(2), (f)(3), (f)(4), (f)(5)(iv) of this section and 

sources not listed in paragraphs (f)(2), (f)(3), (f)(4), 

(f)(5)(iv) of this section must be submitted to EPA no 

later than September 30, 2011. 

(ii) Content of request. Requests must contain the 

following information: 

(A) A list of specific source categories and 

parameters for which the owner or operator is seeking use 

of best available monitoring methods.

(B) A description of the unique or unusual 

circumstances, such as data collection methods that do not 

meet safety regulations, technical infeasibility, or 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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specific laws or regulations that conflict with each 

specific source for which an owner or operator is 

requesting use of best available monitoring methodologies. 

(C) A detailed explanation and supporting 

documentation of how and when the owner or operator will 

receive the services or equipment to comply with all of 

this subpart W reporting requirements.

(iii) Approval criteria. To obtain approval to use 

BAMM after June 30, 2012, the owner or operator must 

demonstrate to the Administrator’s satisfaction that the 

owner or operator faces unique or unusual circumstances 

such as data collection methods that do not meet safety 

regulations, technical infeasibility, or legal issues 

rendering them unable to meet the requirements of this 

subpart.A list of specific source categories and parameters 

for which the owner or operator is seeking use of best 

available monitoring methods.

(iv) A description of the data collection 

methodologies that do not meet safety regulations, 

technical infeasibility, or specific laws or regulations 

that conflict with each specific source for which an owner 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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or operator is requesting use of best available monitoring 

methodologies. 

(v) A detailed explanation and supporting 

documentation of how and when the owner or operator will 

receive the services or equipment to comply with all of 

this subpart W reporting requirements. 

(C) Approval criteria. To obtain approval, the owner 

or operator must demonstrate to the Administrator’s 

satisfaction that the owner or operator faces unique 

safety, technical or legal issues rendering them unable to 

meet the requirements of this subpart.

§98.235 Procedures for estimating missing data.

A complete record of all estimated and/or measured 

parameters used in the GHG emissions calculations is 

required. If data are lost or an error occurs during 

annual emissions estimation or measurements, you must 

repeat the estimation or measurement activity for those 

sources as soon as possible, including in the subsequent 

calendar year if missing data are not discovered until 

after December 31 of the year in which data are collected, 

until valid data for reporting is obtained. Data developed 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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and/or collected in a subsequent calendar year to 

substitute for missing data cannot be used for that 

subsequent year’s emissions estimation. Where missing data 

procedures are used for the previous year, at least 30 days 

must separate emissions estimation or measurements for the 

previous year and emissions estimation or measurements for 

the current year of data collection. For missing data which 

are continuously monitored or measured, (for example flow 

meters), or for missing temperature or pressure data that 

are required under §98.236, the reporter may use best 

available data for use in emissions determinations. The 

reporter must record and report the basis for the best 

available data in these cases. 

§98.236 Data reporting requirements.

In addition to the information required by §98.3(c), 

each annual report must contain reported emissions and 

related information as specified in this section. 

(a) Report annual emissions separately for each of 

the industry segments listed in paragraphs (a)(1) through 

(8) of this section. in metric tons CO2e per year at 

standard conditions. For each segment, report emissions 

from each source type §98.232(a) in the aggregate, unless 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 156 of 206

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specified otherwise. For example, an onshore natural gas 

production operation with multiple reciprocating 

compressors must report emissions from all reciprocating 

compressors as an aggregate number.

(1) Onshore petroleum and natural gas production. 

(2) Offshore petroleum and natural gas production. 

(3) Onshore natural gas processing. 

(4) Onshore natural gas transmission compression. 

(5) Underground natural gas storage. 

(6) LNG storage. 

(7) LNG import and export. 

(8) Natural gas distribution. Report each source in 

the aggregate for pipelines and for Metering and Regulating

(M&R) stations.

(b) For oOffshore petroleum and natural gas 

production, report emissions of CH4, CO2, and N2O as 

applicable to the source type (in metric tons CO2e per year 

at standard conditions) individually for all the emissions 

source types listed in the most recent BOEMRE study. is not 

required to report activity data and emissions for each 

aggregated source under §98.236 (c). Reporting requirements 

for offshore petroleum and natural gas production is set 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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forth by BOEMRE in compliance with 30 CFR 250.302 through 

304.

(c) Report the information listed in this paragraph 

for each applicable source type. If a facility operates 

under more than one industry segment, each piece of 

equipment should be reported under its respective majority 

use segment. When a source type listed under this 

paragraph routes gas to flare, separately report the 

emissions that were vented directly to the atmosphere 

without flaring, and the emissions that resulted from 

flaring the gas. Both the vented and flared emissions will 

be reported under the respective source type and not under 

the flare source type.For each aggregated source, unless 

otherwise specified, report activity data and emissions (in 

metric tons CO2e per year at standard conditions) for each 

aggregated source type as follows:

(1) For natural gas pneumatic devices (refer to 

Equation W-1 of §98.233), report the following: 

(i) Actual count and estimated count separately of 

natural gas pneumatic high bleed devices as applicable. 

(ii) Actual count and estimated count separately of 

natural gas pneumatic low bleed devices as applicable. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(iii) Actual count and estimated count separately of 

natural gas pneumatic intermittent bleed devices as 

applicable. 

(iv) Report annual CO2 and CH4 emissions at the 

facility level, expressed in metric tons CO2e for each gas, 

for each of the following pieces of equipment: high bleed 

pneumatic devices; intermittent bleed pneumatic devices; 

low bleed pneumatic devices.

Report emissions collectively.

(2) For natural gas driven pneumatic pumps (refer to 

Equation W-2 of §98.233), report the following, 

(i) Count of natural gas driven pneumatic pumps. 

(ii) Report annual CO2 and CH4 emissions at the 

facility level, expressed in metric tons CO2e for each gas, 

for all natural gas driven pneumatic pumps combined.Report 

emissions collectively. 

(3) For each acid gas removal unit (refer to Equation 

W-3 and Equation W-4 of §98.233), report the following: 

(i) Total throughput off the acid gas removal unit 

using a meter or engineering estimate based on process 

knowledge or best available data in million cubic feet per 

year. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(ii) For Calculation Methodology 1 and Calculation 

Methodology 2 of §98.233(d), annual average fraction of CO2

content in the vent from the acid gas removal unit (refer 

to §98.233(d)(6)). 

(iii) For Calculation Methodology 3 of §98.233(d), 

annual average volume fraction of CO2 content of natural gas 

into and out of the acid gas removal unit (refer to 

§98.233(d)(7) and (d)(8)). 

(iv) Report the annual quantity of CO2, expressed in 

metric tons CO2e, that was recovered from the AGR unit and 

transferred outside the facility. Report emissions from the 

AGR unit recovered and transferred outside the facility.

(v) Report annual CO2 emissions for the AGR unit, 

expressed in metric tons CO2e.Report emissions individually.

(vi) A unique name or ID number for the AGR unit. 

(vii) An indication of which calculation methodology 

was used for the AGR.

(4) For dehydrators, report the following: 

(i) For each Glycol dehydrator with a throughput 

greater than or equal to 0.4 MMscfd (refer to 

§98.233(e)(1)), report the following: 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(A) Glycol dehydrator feed natural gas flow rate in 

MMscfd, determined by engineering estimate based on best 

available data. 

(B) Glycol dehydrator absorbent circulation pump 

type. 

(C) Whether stripper gas is used in glycol 

dehydrator. 

(D) Whether a flash tank separator is used in glycol 

dehydrator. 

(E) Type of absorbent. 

(F) Total time the glycol dehydrator is operating in 

hours. 

(G) Temperature, in degrees Fahrenheit and pressure, 

in psig, of the wet natural gas. 

(H) Concentration of CH4 and CO2 in wet natural gas. 

(I) What vent gas controls are used (refer to 

§98.233(e)(3) and (e)(4)). 

(J) For each glycol dehydrator, report annual CO2 and 

CH4 emissions that resulted from venting gas directly to the 

atmosphere, expressed in metric tons CO2e for each 

gas.Report vent and flared emissions individually.

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(K) For each glycol dehydrator, report annual CO2, 

CH4, and N2O emissions that resulted from flaring process 

gas from the dehydrator, expressed in metric tons CO2e for 

each gas.

(L) A unique name or ID number for the glycol 

dehydrator.

(ii) For all glycol dehydrators with a throughput 

less than 0.4 MMscfd (refer to §98.233, Equation W-5 of 

§98.233), report the following: 

(A) Count of glycol dehydrators. 

(B) Whether anyWhich vent gas controls are used 

(refer to §98.233(e)(3) and (e)(4)). 

(C) Report annual CO2 and CH4 emissions at the 

facility level that resulted from venting gas directly to 

the atmosphere, expressed in metric tons CO2e for each gas, 

combined for all glycol dehydrators with a throughput of 

less than 0.4 MMscfd.Report vent emissions collectively.

(D) Report annual CO2, CH4, and N2O emissions at the 

facility level that resulted from the flaring of process 

gas, expressed in metric tons CO2e for each gas, combined 

for all glycol dehydrators with a throughput of less than 

0.4 MMscfd. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(iii) For absorbent desiccant dehydrators (refer to 

Equation W-6 of §98.233), report the following: 

(A) Count of desiccant dehydrators. 

(B) Report annual CO2 and CH4 emissions at the 

facility level, expressed in metric tons CO2e for each gas, 

for all absorbent desiccant dehydrators combined.Report 

emissions collectively.

(5) For well venting for liquids unloading (refer to 

Equations W-7, W-8 and W-9 of §98.233), report the 

following by fieldeach well tubing diameter grouping and 

pressure grouping within each sub-basin category: 

(i) Count of wells vented to the atmosphere for 

liquids unloading. 

(ii) Count of plunger lifts. 

(iii) Cumulative number of unloadings vented to the 

atmosphere. 

(iv) Average flow rate of the measured well venting 

in cubic feet per hour (refer to §98.233(f)(1)(i)(A)). 

(v) Average casing diameter in inches. 

(vi) Report annual CO2 and CH4 emissions, expressed in 

metric tons CO2e for each gas, for each tubing diameter and 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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pressure grouping within each sub-basin category.Report 

emissions collectively.

(vii) When using Calculation Methodology 1, casing 

diameter, depth and pressure of each well selected to 

represent emissions in that tubing size and pressure 

combination (refer to Equation W-7 of §98.233).

(6) For well completions and workovers, report the 

following for each fieldsub-basin category: 

(i) For gas well completions and workovers with 

hydraulic fracturing by sub-basin and well type (horizontal 

or vertical) combination (refer to Equation W-10 of 

§98.233): 

(A) Total count of completions in calendar year. 

(B) Average flow rate of the measured well completion 

venting in cubic feet per hour (refer to Equation W-12 of

§98.233)(g)(1)(i) or (g)(1)(ii)).

(C) Total count of workovers in calendar year. 

(D) Average flow rate of the measured well workover 

venting in cubic feet per hour (refer to Equation W-12 of 

§98.233).(g)(1)(i) or (g)(1)(ii)).

(E) Total number of days of gas venting to the 

atmosphere during backflow for completion. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(F) Total number of days of gas venting to the 

atmosphere during backflow for workovers. 

(G) Report number of completions and number of

workovers employing reduced emissions completions and 

engineering estimate based on best available data of the 

amount of gas recovered to sales. 

(H) Annual CO2 and CH4 emissions that resulted from 

venting gas directly to the atmosphere, expressed in metric 

tons CO2e for each gas.Report vent emissions collectively. 

Report flared emissions collectively.

(I) Annual CO2, CH4, and N2O emissions that resulted 

form flares, expressed in metric tons CO2e for each gas.

(ii) For gas well completions and workovers without 

hydraulic fracturing (refer to Equation W-13 of §98.233): 

(A) Total count of completions in calendar year. 

(B) Total count of workovers in calendar year that 

flare gas or vent gas to the atmosphere. 

(C) Total number of days of gas venting to the 

atmosphere during backflow for completion. 

(D) Annual CO2 and CH4 emissions that resulted from 

venting gas directly to the atmosphere, expressed in metric 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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tons CO2e for each gas.Report vent emissions collectively. 

Report flared emissions collectively.

(E) Annual CO2, CH4, and N2O emissions that resulted 

from flares, expressed in metric tons CO2e for each gas.

(7) For each blowdown vent stack (refer to Equation 

W-14 of §98.233), report the following: 

(i) Total number of blowdowns per unique volume 

equipment type in calendar year. 

(ii) Annual CO2 and CH4 emissions, expressed in metric 

tons CO2e for each gas, for each unique volume type, at each 

blowdown stack.Report emissions collectively per equipment 

type. 

(iii) A unique name or ID number for the blowdown 

vent stack.

(8) For gas emitted from produced oil sent to 

atmospheric tanks: 

(i) For wellhead gas-liquid separator with oil 

throughput greater than or equal to 10 barrels per day, 

using Calculation Methodology 1 and 2 of §98.233(j), report 

the following by fieldsub-basin category, unless otherwise

specified: 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(A) Number of wellhead separators sending oil to 

atmospheric tanks. 

(B) Estimated average separator temperature, in 

degrees Fahrenheit, and estimated average pressure, in 

psig. 

(C) Estimated average sales oil stabilized API 

gravity, in degrees. 

(D) Count of hydrocarbon tanks at well pads. 

(E) Best estimate of count of stock tanks not at well 

pads receiving your oil. 

(F) Total volume of oil from all wellhead separators 

sent to tank(s) in barrels per year. 

(G) Count of tanks with emissions control measures, 

either vapor recovery system or flaring, for tanks at well 

pads. 

(H) Best estimate of count of stock tanks assumed to 

have emissions control measures not at well pads, receiving 

your oil. 

(I) Range of concentrations of flash gas, CH4 and CO2. 

(J) Annual CO2 and CH4 emissions that resulted from 

venting gas to the atmosphere, expressed in metric tons CO2e 

for each gas, for each wellhead gas-liquid separator using 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Calculation Methodology 1 or 2 of §98.233(j).Report 

emissions individually for Calculation Methodology 1 and 2 

of §98.233(j). 

(K) Annual CO2 and CH4 gas quantities that were 

recovered, expressed in metric tons CO2e for each gas, for 

each wellhead gas-liquid separator using Calculation 

Methodology 1 or 2 of §98.233(j).

(L) Annual CO2, CH4, and N2O emissions that resulted 

from flaring gas, expressed in metric tons CO2e for each 

gas, for each wellhead gas-liquid separator using 

Calculation Methodology 1 or 2 of §98.233(j).

(M) A unique name or ID number for each wellhead gas 

liquid separator.

(ii) For wells with oil production greater than or 

equal to 10 barrels per day, using Calculation Methodology 

3 and 4 of §98.233(j), report the following by fieldsubbasin category: 

(A) Total volume of sales oil from all wells in 

barrels per year. 

(B) Total number of wells sending oil directly to 

tanks. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(C) Total number of wells sending oil to separators 

off the well pads. 

(D) Sales oil API gravity range for wells in 

(c)(8)(ii)(B) and (c)(8)(ii)(C) of this section, in 

degrees. 

(E) Count of hydrocarbon tanks on wellpads 

(F) Count of hydrocarbon tanks, both on and off well 

pads assumed to have emissions control measures: either 

vapor recovery system or flaring of tank vapors. 

(G) Annual CO2 and CH4 emissions that resulted from 

venting gas to the atmosphere, expressed in metric tons CO2e 

for each gas, at the sub-basin level for Calculation 

Methodology 3 or 4 of §98.233(j).Report emissions 

collectively for Calculation Methodology 3 and 4 of 

§98.233(j). 

(iii) For wellhead gas-liquid separators and wells 

with throughput less than 10 barrels per day, using 

Calculation Methodology 5 of §98.233(j) Equation W-15 of 

§98.233), report the following: 

(A) Number of wellhead separators. 

(B) Number of wells without wellhead separators. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 169 of 206

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(C) Total volume of oil production in barrels per 

year. 

(D) Best estimate of fraction of production sent to 

tanks with assumed control measures: either vapor recovery 

system or flaring of tank vapors. 

(E) Count of hydrocarbon tanks on well pads. 

(F) Annual CO2 and CH4 emissions that resulted from 

venting gas to the atmosphere, expressed in metric tons CO2e 

for each gas, at the sub-basin level for Calculation 

Methodology 5 of §98.233(j).Report CO2 and CH4 emissions 

collectively. 

(G) Annual CO2 and CH4 gas quantities that were 

recovered, expressed in metric tons CO2e for each gas, at 

the sub-basin level for Calculation Methodology 5 of 

§98.233(j).

(H) Annual CO2, CH4, and N2O emissions that resulted 

from flaring gas, expressed in metric tons CO2e for each 

gas, at the sub-basin level for Calculation Methodology 5 

of §98.233(j).

(iv) If wellhead separator dump valve is functioning 

improperly during the calendar year (refer to Equation W-16 

of §98.233), report the following: 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 170 of 206

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(A) Count of wellhead separators that dump valve 

factor is applied. 

(B) Annual CO2 and CH4 emissions that resulted from 

venting gas to the atmosphere, expressed in metric tons CO2e 

for each gas, at the sub-basin level for improperly 

functioning dump valves.

(9) For transmission tank emissions identified using 

optical gas imaging instrument per §98.234(a) (refer to 

§98.233(k)), or acoustic leak detection of scrubber dump 

valves report the following for each tank: 

(i) For each transmission storage tank, report annual 

CO2 and CH4 emissions that resulted from venting gas 

directly to the atmosphere, expressed in metric tons CO2e 

for each gas.Report emissions individually.

(ii) For each transmission storage tank, report 

annual CO2, CH4, and N2O emissions that resulted from 

flaring process gas from the transmission storage tank, 

expressed in metric tons CO2e for each gas. [Reserved]

(iii) A unique name or ID number for the transmission 

storage tank.

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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(10) For well testing venting and flaring (refer to 

Equation W-17 of §98.233), report the following for each 

basin: 

(i) Number of wells tested per basin in calendar 

year. 

(ii) Average gas to oil ratio for each basin. 

(iii) Average number of days the well is tested in a 

basin. 

(iv) Report annual CO2 and CH4 emissions at the 

facility level, expressed in metric tons CO2e for each gas, 

emissions from well testing venting.Report emissions of the 

venting gas collectively.

(v) Report annual CO2, CH4, and N2O emissions at the 

facility level, expressed in metric tons CO2e for each gas, 

emissions from well testing flaring.

(11) For associated natural gas venting (refer to 

Equation W-18 of §98.233), report the following for each 

basin: 

(i) Number of wells venting or flaring associated 

natural gas in a calendar year. 

(ii) Average gas to oil ratio for each basin. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 172 of 206

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(iii) Report annual CO2 and CH4 emissions at the 

facility level, expressed in metric tons CO2e for each gas, 

emissions from associated natural gas venting.Report 

emissions of the flaring gas collectively. 

(iv) Report annual CO2, CH4, and N2O emissions at the 

facility level, expressed in metric tons CO2e for each gas, 

emissions from associated natural gas flaring.

(12) For flare stacks (refer to Equation W-19, W-20, 

and W-21 of §98.233), report the following for each flare: 

(i) Whether flare has a continuous flow monitor. 

(ii) Volume of gas sent to flare in cubic feet per 

year. 

(iii) Percent of gas sent to un-lit flare determined 

by engineering estimate and process knowledge based on best 

available data and operating records. 

(iv) Whether flare has a continuous gas analyzer. 

(v) Flare combustion efficiency. 

(vi) Report uncombusted CH4 emissions, in metric tons 

CO2e (refer to Equation W-19 of §98.233).Report uncombusted 

and combusted CO2 and CH4 emissions separately. 

(vii) Report uncombusted CO2 emissions, in metric tons 

CO2e (refer to Equation W-20 of §98.233). 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 173 of 206

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(viii) Report combusted CO2 emissions, in metric tons 

CO2e (refer to Equation W-21 of §98.233). 

(ix) Report N2O emissions, in metric tons CO2e.

(x) A unique name or ID number for the flare stack.

(xi) In the case that a CEMS is used to measure CO2

emissions for the flare stack, indicate that a CEMS was 

used in the annual report and report the combusted CO2 and 

uncombusted CO2 as a combined number.

(13) For each centrifugal compressor: 

(i) For compressors with wet seals in operational 

mode (refer to Equations W-22 through W-24 of §98.233), 

report the following for each degassing vent: 

(A) Number of wet seals connected to the degassing 

vent. 

(B) Fraction of vent gas recovered for fuel or sales 

or flared. 

(C) Annual throughput in million scf, use an 

engineering calculation based on best available data. 

(D) Type of meters used for making measurements. 

(E) Reporter emission factor for wet seal oil 

degassing vents in cubic feet per hour (refer to Equation 

W-24 of §98.233). 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 174 of 206

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(F) Total time the compressor is operating in hours. 

(G) Report seal oil degassing vent emissions for 

compressors measured (refer to Equation W-22 of §98.233) 

and for compressors not measured (refer to Equation W-23 

and Equation W-24 of §98.233). 

(ii) For wet and dry seal centrifugal compressors in 

operating mode, (refer to Equations W-22 through W-24 of 

§98.233), report the following: 

(A) Total time in hours the compressor is in 

operating mode. 

(B) Reporter emission factor for blowdown vents in 

cubic feet per hour (refer to Equation W-24 of §98.233). 

(C) Report blowdown vent emissions when in operating 

mode (refer to Equation W-23 and Equation W-24 of §98.233). 

(iii) For wet and dry seal centrifugal compressors in 

not operating, depressurized mode (refer to Equations W-22 

through W-24 of §98.233), report the following: 

(A) Total time in hours the compressor is in 

shutdown, depressurized mode. 

(B) Reporter emission factor for isolation valve 

emissions in shutdown, depressurized mode in cubic feet per 

hour (refer to Equation W-24 of §98.233). 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 175 of 206

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(C) Report the isolation valve leakage emissions in 

not operating, depressurized mode in cubic feet per hour 

(refer to Equation W-23 and Equation W-24 of §98.233). 

(iv) Report total annual compressor emissions from 

all modes of operation (refer to Equation W-24 of §98.233). 

(v) For centrifugal compressors in onshore petroleum 

and natural gas production (refer to Equation W-25 of 

§98.233), report the following: 

(A) Count of compressors. 

(B) Report emissions (refer to Equation W-25 of 

§98.233) collectively. 

(14) For reciprocating compressors: 

(i) For reciprocating compressors rod packing 

emissions with or without a vent in operating mode, report 

the following: 

(A) Annual throughput in million scf, use an 

engineering calculation based on best available data. 

(B) Total time in hours the reciprocating compressor 

is in operating mode. 

(C) Report rod packing emissions for compressors 

measured (refer to Equation W-26 of §98.233) and for 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 176 of 206

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compressors not measured (refer to Equation W-27 and 

Equation W-28 of §98.233). 

(ii) For reciprocating compressors blowdown vents not 

manifold to rod packing vents, in operating and standby 

pressurized mode (refer to Equations W-26 through W-28 of 

§98.233), report the following: 

(A) Total time in hours the compressor is in standby, 

pressurized mode. 

(B) Reporter emission factor for blowdown vents in 

cubic feet per hour (refer to §98.233, Equation W-28). 

(C) Report blowdown vent emissions when in operating 

and standby pressurized modes (refer to Equation W-27 and 

Equation W-28 of §98.233). 

(iii) For reciprocating compressors in not operating, 

depressurized mode (refer to Equations W-26 through W-28 of 

§98.233), report the following: 

(A) Total time the compressor is in not operating, 

depressurized mode. 

(B) Reporter emission factor for isolation valve 

emissions in not operating, depressurized mode in cubic 

feet per hour (refer to Equation W-28 of §98.233). 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 177 of 206

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(C) Report the isolation valve leakage emissions in 

not operating, depressurized mode. 

(iv) Report total annual compressor emissions from all 

modes of operation (refer to Equation W-27 and Equation W28 of §98.233). 

(v) For reciprocating compressors in onshore 

petroleum and natural gas production (refer to Equation W29 of §98.233), report the following: 

(A) Count of compressors. 

(B) Report emissions collectively. 

(15) For each equipment leak sources that uses 

emission factors for estimating emissions (refer to 

§98.233(q) and (r). 

(i) For equipment leaks found in each leak survey 

(refer to §98.233(q)), report the following: 

(A) Total count of leaks found in each complete 

survey listed by date of survey and each type of leak 

source for which there is a leaker emission factor in 

Tables W-2, W-3, W-4, W-5, W-6, and W-7 of this subpart. 

(B) For onshore natural gas processing, range of 

concentrations of CH4 and CO2 (refer to Equation W-30 of 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 178 of 206

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§98.233).Concentration of CH4 and CO2 as described in 

Equation W-30 of §98.233.

(C) Report Annual CO2 and CH4 and CO2 emissions, in 

metric tons CO2e for each gas (refer to Equation W-30 of 

§98.233) collectively by equipment type. 

(ii) For equipment leaks calculated using population 

counts and factors (refer to §98.233(r)), report the 

following: 

(A) For source categories §98.230(a)(3), (a)(4), 

(a)(5), (a)(6), and (a)(7), and (a)(8), total count for 

each type of leak source in Tables W-2, W-3, W-4, W-5, and 

W-6 of this subpart for which there is a population 

emission factor, listed by major heading and component 

type. 

(B) For onshore production (refer to §98.230 

paragraph (a)(2)), total count for each type of major 

equipment in Table W-1B and Table W-1C of this subpart, by 

fieldsub-basin category. 

(C) Report CH4 and CO2Annual CO2 and CH4 emissions, in 

metric tons CO2e for each gas (refer to Equation W-31 of 

§98.233) collectively by equipment type. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 179 of 206

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(16) For local distribution companies, report the 

following: 

(i) Number of above grade T-D transfer stationsNumber 

of custody transfer gate stations. 

(ii) Number of below grade T-D transfer 

stations.Number of non-custody transfer gate stations.

(iii) Number of above grade metering-regulating 

stations (this count will include above grade T-D transfer 

stations).Custody transfer gate station meter run leak 

factor (refer to Equation W-32 of §98.233).

(iv) Number of below grade metering-regulating 

stations (this count will include below grade T-D transfer 

stations).Number of below grade M&R stations with inlet 

pressure greater than 300 psig.

(v) Number of below grade M&R stations with inlet 

pressure between 100 and 300 psig.[Reserved]

(vi) Above grade metering-regulating station leak 

factor (refer to Equation W-32 of §98.233).Number of below 

grate M&R stations with inlet pressure less than 100 psig.

(vii) Number of miles of unprotected steel 

distribution mains. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 180 of 206

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(viii) Number of miles of protected steel distribution 

mains. 

(ix) Number of miles of plastic distribution mains. 

(x) Number of miles of cast iron distribution mains. 

(xi) Number of unprotected steel distribution 

services. 

(xii) Number of protected steel distribution services. 

(xiii) Number of plastic distribution services. 

(xiv) Number of copper distribution services. 

(xv) Annual CO2 and CH4 emissions, in metric tons CO2e 

for each gas, from all above grade T-D transfer stations 

combined.Total emissions from each natural gas distribution 

facility. 

(xvi) Annual CO2 and CH4 emissions, in metric tons 

CO2e for each gas, from all below grade T-D transfer 

stations combined. 

(xvii) Annual CO2 and CH4 emissions, in metric tons 

CO2e for each gas, from all above grade metering-regulating 

stations (including T-D transfer stations) combined.

(xviii) Annual CO2 and CH4 emissions, in metric tons 

CO2e for each gas, from all below grade metering-regulating 

stations (including T-D transfer stations) combined.

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 181 of 206

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(xix) Annual CO2 and CH4 emissions, in metric tons 

CO2e for each gas, from all distribution mains combined.

(xx) Annual CO2 and CH4 emissions, in metric tons CO2e 

for each gas, from all distribution services combined.

(17) For each EOR injection pump blowdown (refer to 

Equation W-37 of §98.233), report the following: 

(i) Pump capacity, in barrels per day. 

(ii) Volume of critical phase gas between isolation 

valves. 

(iii) Number of blowdowns per year. 

(iv) Critical phase EOR injection gas density. 

(v) For each EOR pump, report annual CO2 and CH4

emissions, expressed in metric tons CO2e for each gas.Report 

emissions collectively.

(vi) A unique name or ID for the EOR pump.

(18) For EOR hydrocarbon liquids dissolved CO2 for 

each field sub-basin category (refer to Equation W-38 of 

§98.233), report the following: 

(i) Volume of crude oil produced in barrels per year. 

(ii) Amount of CO2 retained in hydrocarbon liquids in 

metric tons per barrel, under standard conditions. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 182 of 206

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(iii) Report annual CO2 emissions at the sub-basin 

level, expressed in metric tons CO2e.Report emissions 

individually.

(19) For onshore petroleum and natural gas production 

and natural gas distribution combustion emissions, report 

the following: 

(i) Cumulative number of external fuel combustion 

units with a rated heat capacity equal to or less than 5 

mmBtu/hr, by type of unit. 

(ii) Cumulative number of external fuel combustion 

units with a rated heat capacity larger than 5 mmBtu/hr, by 

type of unit. 

(iii) Report annual CO2, CH4, and N2O emissions at from 

external fuel combustion units with a rated heat capacity 

larger than 5 mmBtu/hr, expressed in metric tons CO2e for 

each gas, by type of unit.Cumulative emissions from 

external fuel combustion units with a rated heat capacity 

larger than 5 mmBtu/hr, by type of unit.

(iv) Cumulative volume of fuel combusted in external 

fuel combustion units with a rated heat capacity larger 

than 5 mmBtu/hr, by fuel type. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 183 of 206

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(v) Cumulative number of all internal combustion 

units, by type of unit. 

(vi) Report annual CO2, CH4, and N2O emissions from 

internal combustion units, expressed in metric tons CO2e for 

each gas, by type of unit.Cumulative emissions from 

internal combustion units, by type of unit.

(vii) Cumulative volume of fuel combusted in internal 

combustion units, by fuel type. 

(d) Report annual throughput as determined by 

engineering estimate based on best available data for each 

industry segment listed in paragraphs (a)(1) through (a)(8) 

of this section. 

(e) For onshore petroleum and natural gas production, 

report the average API gravity, average gas to oil ratio, 

and average low pressure separator pressure for each subbasin category.

§98.237 Records that must be retained.

Monitoring Plans, as described in §98.3(g)(5), must be 

completed by April 1, 2011. In addition to the information 

required by §98.3(g), you must retain the following 

records: 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 184 of 206

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(a) Dates on which measurements were conducted. 

(b) Results of all emissions detected and 

measurements. 

(c) Calibration reports for detection and measurement 

instruments used. 

(d) Inputs and outputs of calculations or emissions 

computer model runs used for engineering estimation of 

emissions.

(e) The records required under §98.3(g)(2)(i) shall 

include an explanation of how company records, engineering 

estimation, or best available information are used to 

calculate each applicable parameter under this subpart.

§98.238 Definitions.

Except as provided in this section, all terms used in 

this subpart have the same meaning given in the Clean Air 

Act and subpart A of this part. 

Acid gas means hydrogen sulfide (H2S) and/or carbon 

dioxide (CO2) contaminants that are separated from sour 

natural gas by an acid gas removal unit. 

Acid gas removal unit (AGR) means a process unit that 

separates hydrogen sulfide and/or carbon dioxide from sour 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 185 of 206

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natural gas using liquid or solid absorbents or membrane 

separators. 

Acid gas removal vent emissions mean the acid gas 

separated from the acid gas absorbing medium (e.g., an 

amine solution) and released with methane and other light 

hydrocarbons to the atmosphere or a flare.

Associated with a single well-pad means associated 

with the hydrocarbon stream as produced from one or more 

wells located on that single well-pad. The association 

ends where the stream from a single well-pad is combined 

with streams from one or more additional single well-pads, 

where the point of combination is located off that single 

well-pad. This does not include storage and condensate 

tanks that are located downstream of the point of 

combination.

Basin means geologic provinces as defined by the 

American Association of Petroleum Geologists (AAPG) 

Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG 

Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, 

and Fred J. Wagner, Jr., Volume 75, Number 10 (October 

1991) (incorporated by reference, see §98.7) and the Alaska 

Geological Province Boundary Map, Compiled by the American 

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Comment [A2]: Ragan’s Comment: Do we 

really want to limit this to single 

well pads? See previous comment 

about upstream comingling. 

Response: We have included 

coverage from comingling through 

the “associated” term. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Association of Petroleum Geologists Committee on Statistics 

of Drilling in Cooperation with the USGS, 1978 

(incorporated by reference, see §98.7). 

Component means each metal to metal joint or seal of 

non-welded connection separated by a compression gasket, 

screwed thread (with or without thread sealing compound), 

metal to metal compression, or fluid barrier through which 

natural gas or liquid can escape to the atmosphere. 

Compressor means any machine for raising the pressure 

of a natural gas or CO2 by drawing in low pressure natural 

gas or CO2 and discharging significantly higher pressure 

natural gas or CO2. 

Condensate means hydrocarbon and other liquid, 

including both water and hydrocarbon liquids, separated 

from natural gas that condenses due to changes in the 

temperature, pressure, or both, and remains liquid at 

storage conditions. 

Distribution pipeline means a pipeline that is 

designated as such by the Pipeline and Hazardous Material 

Safety Administration (PHMSA) 49 C.F.R. §192.3.

Engineering estimation, for purposes of subpart W,

means an estimate of emissions based on engineering 

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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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principles applied to measured and/or approximated physical 

parameters such as dimensions of containment, actual 

pressures, actual temperatures, and compositions. 

Enhanced oil recovery (EOR) means the use of certain 

methods such as water flooding or gas injection into 

existing wells to increase the recovery of crude oil from a 

reservoir. In the context of this subpart, EOR applies to 

injection of critical phase or immiscible carbon dioxide 

into a crude oil reservoir to enhance the recovery of oil. 

Equipment leak means those emissions which could not 

reasonably pass through a stack, chimney, vent, or other 

functionally-equivalent opening. 

Equipment leak detection means the process of 

identifying emissions from equipment, components, and other 

point sources. 

External combustion means fired combustion in which 

the flame and products of combustion are separated from 

contact with the process fluid to which the energy is 

delivered. Process fluids may be air, hot water, or 

hydrocarbons. External combustion equipment may include 

fired heaters, industrial boilers, and commercial and 

domestic combustion units. 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 188 of 206

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Facility with respect to natural gas distribution for 

purposes of reporting under this subpart and for the 

corresponding subpart A requirements means the collection 

of all distribution pipelines and metering-regulating 

stations, metering stations, and regulating stations that 

are operated by a Local Distribution Company (LDC) within a 

single state that is regulated as a separate operating 

company by a public utility commission or that are operated 

as an independent municipally-owned distribution system. 

Facility with respect to onshore petroleum and natural 

gas production for purposes of reporting under this subpart 

and for the corresponding subpart A requirements means all 

petroleum or natural gas equipment on a well- pad or 

associated with a well- pad and CO2 EOR operations that are 

under common ownership or common control including leased, 

rented, or contracted activities by an onshore petroleum 

and natural gas production owner or operator and that are 

located in a single hydrocarbon basin as defined in 

§98.238. Where a person or entity owns or operates more 

than one well in a basin, then all onshore petroleum and 

natural gas production equipment associated with all wells 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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that the person or entity owns or operates in the basin 

would be considered one facility. 

Farm Taps are pressure regulation stations that 

deliver gas directly from transmission pipelines to 

generally rural customers. The gas may or may not be 

metered, but always does not pass through a city gate 

station. In some cases a nearby LDC may handle the billing 

of the gas to the customer(s). 

Field means oil and gas fields identified in the 

United States as defined by the Energy Information 

Administration Oil and Gas Field Code Master List 2008, 

DOE/EIA 0370(08) (incorporated by reference, see §98.7).

Flare, for the purposes of subpart W, means a 

combustion device, whether at ground level or elevated, 

that uses an open or closed flame to combust waste gases 

without energy recovery.

Flare stack emissions means CO2 and N2O from partial 

combustion of hydrocarbon gas sent to a flare plus CH4

emissions resulting from the incomplete combustion of 

hydrocarbon gas in flares. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Flare combustion efficiency means the fraction of 

hydrocarbon gas, on a volume or mole basis, that is 

combusted at the flare burner tip.

Forced extraction of natural gas liquids means removal 

of ethane or higher carbon number hydrocarbons existing in 

the vapor phase in natural gas, by removing ethane or 

heavier hydrocarbons derived from natural gas into natural 

gas liquids by means of a forced extraction process. 

Forced extraction processes include but are not limited to 

refrigeration, absorption (lean oil), cryogenic expander, 

and combinations of these processes. Forced extraction 

does not include in and of itself; natural gas dehydration, 

or the collection or gravity separation of water or 

hydrocarbon liquids from natural gas at ambient temperature 

or heated above ambient temperatures, or the condensation 

of water or hydrocarbon liquids through passive reduction 

in pressure or temperature, or portable dewpoint 

suppression skids.

Gas well means a well completed for production of 

natural gas (including condensate) from one or more gas 

zones or reservoirs. Such wells contain no completions for 

the production of crude oil.

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Horizontal well means a well bore that has a planned 

deviation from primarily vertical to a primarily horizontal 

inclination or declination tracking in parallel with and 

through the target formation.

Internal combustion means the combustion of a fuel 

that occurs with an oxidizer (usually air) in a combustion 

chamber. In an internal combustion engine the expansion of 

the high-temperature and –pressure gases produced by 

combustion applies direct force to a component of the 

engine, such as pistons, turbine blades, or a nozzle. This 

force moves the component over a distance, generating 

useful mechanical energy. Internal combustion equipment may 

include gasoline and diesel industrial engines, natural 

gas-fired reciprocating engines, and gas turbines. 

Liquefied natural gas (LNG) means natural gas 

(primarily methane) that has been liquefied by reducing its 

temperature to -260 degrees Fahrenheit at atmospheric 

pressure. 

LNG boil-off gas means natural gas in the gaseous 

phase that vents from LNG storage tanks due to ambient heat 

leakage through the tank insulation and heat energy 

dissipated in the LNG by internal pumps.

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Metering-regulating station means a station that 

meters the flowrate, regulates the pressure, or both, of 

natural gas in a natural gas distribution facility. This 

does not include customer meters, customer regulators, or 

farm taps.

Offshore means seaward of the terrestrial borders of 

the United States, including waters subject to the ebb and 

flow of the tide, as well as adjacent bays, lakes or other 

normally standing waters, and extending to the outer 

boundaries of the jurisdiction and control of the United 

States under the Outer Continental Shelf Lands Act. 

Oil well means a well completed for the production of 

crude oil from at least one oil zone or reservoir. 

Onshore petroleum and natural gas production owner or 

operator means the person or entity who holds the permit to 

operate petroleum and natural gas wells on the drilling 

permit or an operating permit where no drilling permit is 

issued, which operates an onshore petroleum and/or natural 

gas production facility (as described in §98.230(a)(2). 

Where petroleum and natural gas wells operate without a 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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drilling or operating permit, the person or entity that 

pays the State or Federal business income taxes is 

considered the owner or operator. 

Operating pressure means the containment pressure that 

characterizes the normal state of gas or liquid inside a 

particular process, pipeline, vessel or tank.

Pressure groupings are defined as follows: less than 

or equal to 25 psig; greater than 25 psig and less than or 

equal to 60 psig; greater than 60 psig and less than or 

equal to 110 psig; greater than 110 psig and less than or 

equal to 200 psig; and greater than 200 psig.

Pump means a device used to raise pressure, drive, or 

increase flow of liquid streams in closed or open conduits. 

Pump seals means any seal on a pump drive shaft used 

to keep methane and/or carbon dioxide containing light 

liquids from escaping the inside of a pump case to the 

atmosphere. 

Pump seal emissions means hydrocarbon gas released 

from the seal face between the pump internal chamber and 

the atmosphere. 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Reservoir means a porous and permeable underground 

natural formation containing significant quantities of 

hydrocarbon liquids and/or gases. 

Residue Gas and Residue Gas Compression mean, 

respectively, production lease natural gas from which gas 

liquid products and, in some cases, non-hydrocarbon 

components have been extracted such that it meets the 

specifications set by a pipeline transmission company, 

and/or a distribution company; and the compressors operated 

by the processing facility, whether inside the processing 

facility boundary fence or outside the fence-line, that 

deliver the residue gas from the processing facility to a 

transmission pipeline. 

Separator means a vessel in which streams of multiple 

phases are gravity separated into individual streams of 

single phase.

Sub-basin category, for onshore natural gas 

production, means a subdivision of a basin into the unique 

combination of wells with the surface coordinates within 

the boundaries of an individual county and subsurface 

completion in one or more of each of the following four 

formation types as designated by 18 C.F.R. 270.305: 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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conventional with >0.1 millidarci permeability, and 

unconventional with ≤0.1 millidarci permeability. 

Unconventional formation types are either shale, coal seam, 

or other tight reservoir rock. Wells producing from more 

than one unconventional formation type shall be classified 

into only one type based on the formation with the most 

contribution to production as determined by engineering 

knowledge. Unconventional wells producing in two or more 

formation types of “shale and coal seam”, “shale and other 

tight”, or “shale, coal seam, and other tight”; are 

considered shale. In addition, unconventional wells 

producing in “coal seam and other tight" formations are 

considered coal.

Transmission-distribution (TD) transfer station means 

a meter-regulating station where a local distribution 

company takes part or all of the natural gas from a 

transmission pipeline and puts it into a distribution 

pipeline.

Transmission pipeline means a Federal Energy 

Regulatory Commission rate-regulated Interstate pipeline, a 

state rate-regulated Intrastate pipeline, or a pipeline 

that falls under the “Hinshaw Exemption” as referenced in 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 

(w)(1994) .means high pressure cross country pipeline 

transporting saleable quality natural gas from production 

or natural gas processing to natural gas distribution 

pressure let-down, metering, regulating stations where the 

natural gas is typically odorized before delivery to 

customers.

Tubing diameter groupings are defined as follows: 

less than or equal to 1 inch; greater than 1 inch and less 

than 2 inch; and greater than or equal to 2 inch.

Tubing systems means piping equal to or less than one 

half inch diameter as per nominal pipe size.

Turbine meter means a flow meter in which a gas or 

liquid flow rate through the calibrated tube spins a 

turbine from which the spin rate is detected and calibrated 

to measure the fluid flow rate. 

Vented emissions means intentional or designed 

releases of CH4 or CO2 containing natural gas or hydrocarbon 

gas (not including stationary combustion flue gas), 

including process designed flow to the atmosphere through 

seals or vent pipes, equipment blowdown for maintenance, 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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and direct venting of gas used to power equipment (such as 

pneumatic devices).

Vertical well means a well bore that is primarily 

vertical but has some unintentional deviation or one or 

more intentional deviations to enter one or more subsurface 

targets that are off-set horizontally from the surface 

location, intercepting the targets either vertically or at 

an angle.

Well testing venting and flaring means venting and/or 

flaring of natural gas at the time the production rate of a 

well is determined (i.e., the well testing) through a choke 

(an orifice restriction). If well testing is conducted 

immediately after well completion or workover, then it is

considered part of well completion or workover.

TABLE W-1A OF SUBPART W–DEFAULT WHOLE GAS EMISSION FACTORS 

FOR ONSHORE PETROLEUM AND NATURAL GAS PRODUCTION 

Onshore petroleum and natural gas production Emission Factor 

(scf/hour/component) 

Eastern U.S. 

Population Emission Factors - All Components, 

Gas Service1 

Valve 0.027 

Connector 0.004 

Open-ended Line 0.062 

Pressure Relief Valve 0.041 

Low Continuous Bleed Pneumatic Device 

Vents2 1.80 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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High Continuous Bleed Pneumatic Device 

Vents2 48.1 

Intermittent Bleed Pneumatic Device Vents2 17.4 

Pneumatic Pumps3 13.3 

Population Emission Factors - All Components, 

Light Crude Service4 

Valve 0.04 

Flange 0.002 

Connector 0.005 

Open-ended Line 0.04 

Pump 0.01 

Other5 0.23 

Population Emission Factors - All Components, 

Heavy Crude Service6 

Valve 0.0004 

Flange 0.0007 

Connector (other) 0.0002 

Open-ended Line 0.004 

Other5 0.002 

Western U.S. 

Population Emission Factors - All Components, 

Gas Service1

Valve 0.123 

Connector 0.017 

Open-ended Line 0.032 

Pressure Relief Valve 0.196 

Low Continuous Bleed Pneumatic Device 

Vents2 1.80 

High Continuous Bleed Pneumatic Device 

Vents2 48.1 

Intermittent Bleed Pneumatic Device Vents2 17.4 

Pneumatic Pumps3 13.3 

Population Emission Factors - All Components, 

Light Crude Service4

Valve 0.04 

Flange 0.002 

Connector (other) 0.005 

Open-ended Line 0.04 

Pump 0.01 

Other5 0.23 

Population Emission Factors - All Components, 

Heavy Crude Service6

Valve 0.0004 

Flange 0.0007 

Connector (other) 0.0002 

Open-ended Line 0.004 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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TABLE W-1B OF SUBPART W–DEFAULT AVERAGE COMPONENT COUNTS FOR 

MAJOR ONSHORE NATURAL GAS PRODUCTION EQUIPMENT 

Major Equipment Valves Connectors Open-ended 

Lines 

Pressure 

relief 

valves 

Eastern U.S. 

Wellheads 8 38 0.5 0 

Separators 1 6 0 0 

meters/piping 12 45 0 0 

Compressors 12 57 0 0 

In-line heaters 14 65 2 1 

Dehydrators 24 90 2 2 

Western U.S. 

Wellheads 11 36 1 0 

Separators 34 106 6 2 

meters/piping 14 51 1 1 

Compressors 73 179 3 4 

In-line heaters 14 65 2 1 

Dehydrators 24 90 2 2 

Table W-1C of Subpart W of Part 98 Default Average 

Component Counts For Major Crude Oil Production Equipment 

Major Equipment Valves Flanges Connecto

rs 

Openended 

Lines 

Other 

Components 

Eastern U.S. 

Wellhead 5 10 4 0 1 

Separator 6 12 10 0 0 

Heater-treater 8 12 20 0 0 

Header 5 10 4 0 0 

Western U.S. 

Wellhead 5 10 4 0 1 

Separator 6 12 10 0 0 

Heater-treater 8 12 20 0 0 

Other5 0.002 1

 For multi-phase flow that includes gas, use the gas service emissions 

factors 

2

 Emission Factor is in units of "scf/hour/device" 

3

 Emission Factor is in units of "scf/hour/pump" 

4

 Hydrocarbon liquids greater than or equal to 20 ̊API are considered 

"light crude" 

5

 ”Others” category includes instruments, loading arms, pressure relief 

valves, stuffing boxes, compressor seals, dump lever arms, and vents.

6

 Hydrocarbon liquids less than 20 ̊API are considered "heavy crude" 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Header 5 10 4 0 0 

Table W-1D of Subpart W of Part 98 Designation Of Eastern 

And Western U.S.

Eastern U.S. Western U.S. 

Connecticut Alabama 

Delaware Alaska 

Florida Arizona 

Georgia Arkansas 

Illinois California 

Indiana Colorado 

Kentucky Hawaii 

Maine Idaho 

Maryland Iowa 

Massachusetts Kansas 

Michigan Louisiana 

New Hampshire Minnesota 

New Jersey Mississippi 

New York Missouri 

North Carolina Montana 

Ohio Nebraska 

Pennsylvania Nevada 

Rhode Island New Mexico 

South Carolina North Dakota 

Tennessee Oklahoma 

Vermont Oregon 

Virginia South Dakota 

West Virginia Texas 

Wisconsin Utah 

Washington 

Wyoming 

TABLE W-2 OF SUBPART W–DEFAULT TOTAL HYDROCARBON EMISSION 

FACTORS FOR ONSHORE NATURAL GAS PROCESSING 

Onshore natural gas processing Emission Factor 

(scf/hour/component) 
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solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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Leaker Emission Factors - Compressor Components, Gas Service 

Valve1 15.07

Connector 5.68

Open-Ended Line 17.54

Pressure Relief Valve 40.27

Meter 19.63

Leaker Emission Factors – Non-Compressor Components, Gas Service 

Valve 6.52

Connector 5.80

Open-Ended Line 11.44

Pressure Relief Valve 2.04

Meter 2.98 1 Valves include control valves, block valves and regulator valves. 

TABLE W-3 OF SUBPART W–DEFAULT TOTAL HYDROCARBON EMISSION 

FACTORS FOR ONSHORE NATURAL GAS TRANSMISSION COMPRESSION 

Onshore natural gas transmission 

compression 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - Compressor Components, Gas Service 

Valve1 15.07

Connector 5.68

Open-Ended Line 17.54

Pressure Relief Valve 40.27

Meter 19.63

Leaker Emission Factors – Non-Compressor Components, Gas Service 

Valve1 6.52

Connector 5.80

Open-Ended Line 11.44

Pressure Relief Valve 2.04

Meter 2.98

Population Emission Factors – Gas Service 

Low Continuous Bleed Pneumatic Device 

Vents2 1.7941

High Continuous Bleed Pneumatic Device 

Vents2 2018.18

Intermittent Bleed Pneumatic Device 

Vents2 2018.18 1

 Valves include control valves, block valves and regulator valves. 

2

 Emission Factor is in units of "scf/hour/device" 
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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TABLE W-4 OF SUBPART W–DEFAULT TOTAL HYDROCARBON EMISSION 

FACTORS FOR UNDERGROUND NATURAL GAS STORAGE 

Underground natural gas storage 

Emission Factor 

(scf/hour/componen

t) 

Leaker Emission Factors - Storage Station, Gas Service 

Valve1 15.07 

Connector 5.68 

Open-Ended Line 17.54 

Pressure Relief Valve 40.27 

Meter 19.63 

Population Emission Factors - Storage Wellheads, Gas Service

Connector 0.01 

Valve 0.10 

Pressure Relief Valve 0.17 

Open-ended Line 0.03 

Population Emission Factors - Other Components, Gas Service

Low Continuous Bleed Pneumatic Device Vents2 1.7941

High Continuous Bleed Pneumatic Device Vents2 2018.18

Intermittent Bleed Pneumatic Device Vents2 2018.18 1

 Valves include control valves, block valves and regulator valves.

2

 Emission Factor is in units of "scf/hour/device" 

TABLE W-5 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

LIQUEFIED NATURAL GAS (LNG) STORAGE 

LNG Storage 

Emission Factor 

(scf/hour/compone

nt) 

Leaker Emission Factors - LNG Storage Components, LNG Service

Valve 1.21 

Pump Seal 4.06 

Connector 0.35 

Other1 1.80 

Population Emission Factors - LNG Storage Compressor, Gas Service

Vapor Recovery Compressor2 4.23 1

 "other" equipment type should be applied for any equipment type other 

than connectors, pumps, or valves. 2

E

m

i

s

s

i
DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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n

F

a

c

t

o

r

i

s

i

n

u

n

i

t

s

o

f

"

s

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

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TABLE W-6 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

LNG IMPORT AND EXPORT EQUIPMENT 

LNG import and export equipment 

Emission Factor 

(scf/hour/componen

t) 

Leaker Emission Factors - LNG Terminals Components, LNG Service

Valve 1.21 

Pump Seal 4.06 

Connector 0.35 

Other1 1.80 

Population Emission Factors - LNG Terminals Compressor, Gas Service

Vapor Recovery Compressor2 4.23 1

 "other" equipment type should be applied for any equipment type other 

than connectors, pumps, or valves. 2

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 205 of 206

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LNG import and export equipment 

Emission Factor 

(scf/hour/componen

t) 

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TABLE W-7 OF SUBPART W–DEFAULT METHANE EMISSION FACTORS FOR 

NATURAL GAS DISTRIBUTION 

Natural gas distribution Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - Above Grade M&R at City GateTransmissiondistribution Transfer Stations1

 Components, Gas Service 

Connector 1.72 

Block Valve 0.566 

Control Valve 9.48 

Pressure Relief Valve 0.274 

Orifice Meter 0.215 

Regulator 0.784 

Open-ended Line 26.533 

Population Emission Factors - Below Grade Metering-Regulating station&R12

Components, Gas Service23

Below Grade M&R Station, Inlet Pressure > 300 

psig 1.32 

Below Grade M&R Station, Inlet Pressure 100 to 

300 psig 0.20 

Below Grade M&R Station, Inlet Pressure < 100 

psig 0.10 

Population Emission Factors - Distribution Mains, Gas Service34 

Unprotected Steel 12.77 

Protected Steel 0.36 

Plastic 1.15 

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DRAFT -- This draft only contains redline/strikeout text. This document is provided 

solely for informational purposes. It does not provide legal advice, have legally binding 

effect, or expressly or implicitly create, expand, or limit any legal rights, 

obligations, responsibilities, expectations, or benefits in regard to any person. The 

purpose of this redline is to facilitate public review of the 2011 Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule."

Page 206 of 206

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Natural gas distribution Emission Factor 

(scf/hour/component) 

Cast Iron 27.67 

Population Emission Factors - Distribution Services, Gas Service5Service4

Unprotected Steel 0.19 

Protected Steel 0.02 

Plastic 0.001 

Copper 0.03 1 City gate stations at custody transfer and excluding customer meters 12

 Excluding customer meters 23

 Emission Factor is in units of "scf/hour/station" 34

 Emission Factor is in units of "scf/hour/mile" 45 Emission Factor is in units of “scf/hour/number of services” 

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