1

MEMORANDUM

FROM: Akachi Imegwu, U.S. EPA, Climate Change Division

TO: Docket EPA-HQ-OAR-2011-0512, 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

DATE: August 17, 2011

SUBJECT: Summary of questions raised on subpart W of the final Mandatory 

Reporting of Greenhouse Gases Rule (40 CFR Part 98) after promulgation that are 

addressed in the proposed action: 2011 Technical Revisions to the Electronics 

Manufacturing and the Petroleum and Natural Gas Systems Categories of the 

Greenhouse Gas Reporting Rule

1.0 INTRODUCTION

The 2010 final rule for Subpart W of the Greenhouse Gas Reporting Rule (Subpart W) was 

signed by EPA Administrator Lisa Jackson on November 8, 2010 and published in the Federal 

Register on November 30, 2010 (75 FR 74458). The 2010 final rule, which became effective on 

December 31, 2010, included reporting of GHGs from facilities containing petroleum and natural gas 

systems. The rule does not require control of GHGs, rather it only requires that facilities containing 

petroleum and natural gas systems with emissions sources above certain threshold levels monitor and 

report emissions and other related data.

Since promulgation of the final rule in November 2010, EPA has received several questions 

from reporters and trade associations. In addition, the Administrator has identified within subpart W a 

number of technical issues that need to be revised and specific provisions that need to be clarified. 

EPA is proposing to amend specific provisions in Subpart W to make technical and editorial revisions

that have been identified since promulgation and to propose clarifying or other amendments to certain 

provisions that have been the subject of questions from reporting entities. 

The purpose of this memorandum is to describe the extent of EPA‟s outreach efforts for Part 

98, subpart W, and to summarize the questions that have been raised during EPA‟s outreach activities 

that are being addressed by some of the proposed amendments. 

2.0 SUMMARY OF EPA OUTREACH ACTIVITIES ON THE GREENHOUSE GAS 

PROGRAM

EPA has conducted an extensive outreach program for the Greenhouse Gas Program, including 

meetings with trade associations and individual businesses, on-line web-based seminars (webinars), 

and training sessions for EPA Regional Offices. A subset of those meetings were specifically targeted 

for subpart W reporters. The following table lists those meetings and webinars that EPA has conducted 

to date, along with the month and year of the activity. When available, the table also includes the 

approximate attendance for the meeting or webinar. In addition, the meetings and webinars that were 

specifically targeted to subpart W reporters are in yellow highlighted text. 
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POST-SIGNATURE MEETINGS AND WEBINARS

Month and Year of Information Meeting or Webinar

Organization or Location (estimated attendance, if available) 

Sept 2009

EPA Regional Offices Briefing (100)

Agriculture community teleconference (100)

State and Local Agencies teleconference (100)

Clean Energy Group Meeting (about 40)

State of Washington (2)

Business Council (73)

Call with Massachusetts on data system (2)

Overview webinar (293)

US Climate Action Partnership (20)

Overview webinar (284)

National Cooperative Refinery Association, and Van Arsdall & Associates

Oct 2009

Oil and Gas Compact (30)

Portland Cement Assoc. (20)

CENSARA(50)

Overview webinar (217)

Applicability Tool Demonstration (84)

National Lime Assoc. (3)

Detailed webinar (252)

EEI (80)

NACAA (75)

Nitric Acid and Ammonia Assoc.(30)

TFI, AISI, SMA

Overview webinar (176)

Detailed webinar (208)

Air Program Managers and staff (25)

Detailed webinar (206)

Aluminum Industry 

Steel Manufacturers Assoc.

Natural Gas Star 

Overview webinar (133)

Carolina Air Pollution Control Assoc. (400)

Applicability Tool Demonstration (238)

Waste Management and Equipment Companies (25)

Ohio Manure Storage 

Overview webinar (251)

Corporate Climate Regulation, Chicago, IL

Midwest Transportation & Air Quality Conference 

Detailed webinar (333)

TCR/CAA (90)

Environmental Groups (10)

API 
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POST-SIGNATURE MEETINGS AND WEBINARS

Month and Year of Information Meeting or Webinar

Organization or Location (estimated attendance, if available) 

NOV 2009

Misc. Meetings with Industries (Refineries, Pulp and Paper, Cement) (100)

Northeast Gas Assoc. 

Ecology and Environment, Inc. (2)

Detailed webinar (253)

TCR 

Tribal Air Coordinators (50)

GHG data exchange discussion with New Mexico (8)

API (20)

ABA (100)

Training for three regional cap and trade programs – DC (70)

State-EPA Dialogue - DC (80)

Treated Wood Council (60)

Detailed webinar (172)

MAPI (Manufacturing Alliance) (15)

Environmental Services Corporation (150)

Western Climate Initiative partner meeting – Santa Fe (50)

Detailed webinar (171)

Regional Climate sub-leads (40)

Air Products (5)

Waste Management and others (10)

Detailed webinar (96)

DEC 2009

AWMA-EPA- RTP (100)

Envirosys (4)

Detailed webinar (50)

ACC (5)

National Grid 

Detailed webinar (91)

Utilitpoint and Allegro (115)

CARB 

NPRA and API

Golder and Associates

Anadarko (10)

Kinder Morgan 

EEI 

SWANA- LFGTE 

Thermo Fisher Scientific 

EPA Region 4 Training (100)

Waste Management and others (8)

Air Products (5)

The Fertilizer Institute

ADM (8)
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POST-SIGNATURE MEETINGS AND WEBINARS

Month and Year of Information Meeting or Webinar

Organization or Location (estimated attendance, if available) 

JAN 2010

Detailed webinar (83)

Air Products 

National Emissions Inventory (30)

OECA- Regional offices (30)

National Grid

Alliance of Automobile Manufacturers (9)

Detailed webinar (100)

NRPA (300)

Feb 2010

Dedicated webinar for American Colleges and Universities (220)

EPA Regional Inventory, Enforcement (23)

University Challenge

State webinar (200)

Webinar (182)

Iowa Landfill operators (125), Asphalt Paving Association of Iowa (70), and the Iowa Chapter of AMWA (60).

Mar 2010

Inst. Of Clean Air Companies (23)

SWANA (200)

EPA AFS Compliance Meeting 

Second Nature (Colleges/Universities) Panel (20)

ECOS (50)

PCA 

Training- EPA Regions 5 and 7 (180)

Iowa Landfills (50)

April 2010

Arkansas Environmental Federation, Little Rock (160)

NACAA Emissions and Modeling Committee (30)

Webinar (75)

Central TX AWMA (50)

Chicago Exchange Meeting

Exchange Network National Meeting (50)

EPA Air Division Directors (20)

National Assoc. of Clean Water Agencies

Pepsico-Frito Lay (150)

Pacific NW Legislative Energy Horizon Inst./AGA (35)

May 2010

LA, Boise, Portland Training (150, 100, 70, respectively)

ESC Users Group (150)

NCASI 

EPRI CEMUG (150)

June 2010

Webinar: Q&A Session (54)

October 2010

e-GGRT Training (748)
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POST-SIGNATURE MEETINGS AND WEBINARS

Month and Year of Information Meeting or Webinar

Organization or Location (estimated attendance, if available) 

e-GGRT Training (566)

November 2010

e-GGRT Training (521)

Webinar: Subpart FF (44)

General Stakeholder Call: Subparts RR and UU (88)

December 2010

EPA Regional Offices Briefing 

NACAA 

Webinar: Subpart I (71)

Webinar: Subpart W (481)

Webinar: Subparts RR and UU (77)

Webinar: e-GGRT and OTAQREG Training (386)

Webinar: Subpart W (130)

January 2011

Webinar: Subpart W (138)

Webinar: e-GGRT Training (512)

February 2011

Webinar: Overview (98)

EEI: Subpart RR

May 2011

Webinar: Overview

Webinar: Subpart OO

June 2011

Webinar: Overview

3.0 SUMMARY OF QUESTIONS FROM THE EPA HELPLINE AND TRADE

ASSOCIATIONS BEING ADDRESSED BY PROPOSED AMENDMENTS

EPA has maintained a web-based helpline that allows individuals to submit questions about

subpart W. So far, EPA has resolved over 300 inquiries submitted on subpart W, since publication of 

the final rule in 2010. Most of those inquiries have been resolved by providing further guidance to 

reporting entities through a web-based list of answers to frequently asked questions. However, several 

additional questions would be resolved through the proposed amendments to subpart W.

The EPA has also held meetings with several trade associations representing industries affected 

by Part 98, and many questions were presented by those trade associations that would be resolved 

through the proposed amendments to subpart W.

For a summary of the questions that have been submitted through the EPA helpline along with 

questions and issues raised by trade associations on subpart W which are being addressed by the 

proposed technical revisions, please see Appendix A, “Summary of Questions and Issues from the 

EPA Helpline and Trade Associations Being Resolved By the Proposed Technical Corrections and 

Other Amendments.” Not all of the technical revisions and other amendments correspond directly to 

questions that were raised by reporters. The need for some corrections and other amendments were 

identified as a result of internal EPA review stemming from reporter questions and may not be 
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reflected in Appendix A. Any specific identifying information from the incoming questions has not 

been included in Appendix A. 

4.0 SUMMARY OF ISSUES FROM INTERNAL REVIEW BEING ADDRESSED BY 

PROPOSED AMENDMENTS

As mentioned above, not all of the corrections and other amendments correspond directly to questions 

that were raised by reporters. The need for some corrections and other amendments were identified as 

a result of internal EPA review. For a summary of the issues that have been raised from the EPA‟s 

review of Subpart W of Part 98 which are being addressed by the proposed 2011 revisions package, 

please see Appendix B, “Summary of Issues From Internal Review Being Addressed by Proposed 

Amendments”.

APPENDICES TABLE OF CONTENTS

APPENDIX A

Summary of Questions and Issues From The EPA Helpline And Trade Associations Being Resolved By The 

Proposed Technical Corrections And Other Amendments

APPENDIX B

Summary of Issues From Internal Review Being Addressed by Proposed Amendments

APPENDIX C

Percent Gas Composition for Natural Gas Transmission Compression, Underground Natural Gas Storage, 

Liquefied Natural Gas (LNG) Storage, LNG Import and Export, and Natural Gas Distribution Industry 

Segments for Methane and Carbon Dioxide

APPENDIX D

Proposed Pressure Groupings for Monitoring Emissions from the Well Venting for Liquids Unloading 

Emissions Source by Sub-Basin.

APPENDIX E:

Impact on Emissions Coverage Resulting from Proposed Amendments
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Appendix
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Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

Subpart W – Petroleum and Natural Gas

1.Clarifying the equipment 

associated with onshore 

petroleum and natural gas 

production.

Is everything upstream of the gathering line covered by Onshore 

Production segment?

At least 4 

individuals

Helpline

Does Onshore Production portable equipment include only well drilling 

and completion equipment, workover equipment, natural gas dehydrators, 

natural gas compressors, electrical generators, steam boilers, and process 

heaters located on a well pad?

Helpline

Are Tank Vapor Recovery (TVR) and Casing Vapor Recovery (CVR) gas 

compressors included in Onshore Production segment?

Helpline

Are dehydrators located at wellpads (on shore natural gas production 

facilities) considered processing equipment under onshore natural gas 

processing as defined in 98.230- Subpart W Petroleum and Natural Gas 

Facilities?

Helpline

2.Clarify that the onshore 

natural gas processing 

industry segment includes 

the separation of natural 

gas liquids into its 

components and that 

separation is forced 

extraction.

Under Subpart W of Part 98, the definition of Natural Gas Processing 

provides an unclear explanation of fractionation, additionally, fractionation 

is not defined within the rule. The definition is as follows: 

Natural gas processing separates and recovers natural gas liquids (NGLs) 

and/or other non-methane gases and liquids from a stream of produced 

natural gas using equipment performing one or more of the following 

processes: 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 CO2separated from natural gas 

streams. This segment also includes all residue gas compression equipment 

owned or operated by the natural gas processing facility, whether inside or 

outside the processing facility fence. This source category does not include 

reporting of emissions from gathering lines and boosting stations. This 

At least 2 

individual

Helpline
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Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

source category includes:

(i) All processing facilities that fractionate.

(ii) All processing facilities that do not fractionate with throughput of 

25 MMscf per day or greater.

The confusion lies as to what is actually meant by fractionation. Under the 

NSPS Subpart KKK, fractionation is the separating of natural gas liquids 

into natural gas products. However, under the description of processing as 

provided above, it includes "separation of natural gas liquids" and 

"fractionate" as part of what processing plants do. 

The main concern is if a plant that do not fractionate NGLs (as defined in 

Subpart KKK of the NSPS) is processes less than 25 MMscf/day but still 

separates out NGLs from the gas stream if they still meet the definition of 

"processing" or if they are then brought into "production" under the 

definition of a facility. 

Some clarification on this matter would be greatly appreciated.

1.25 mmscf/day is design capacity for a processing plant or the actual in 

the following definition in 98.230(a)(3):

Onshore natural gas processing. Natural gas processing separates and 

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

liquids from a stream of produced natural gas using equipment 

performing one or more of the following processes: 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 facility, whether inside or outside 

Helpline
10

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

the processing facility fence. This source category does not include 

reporting of emissions from gathering lines and boosting stations. This 

source category includes:

(i) All processing facilities that fractionate.

(ii) All processing facilities that do not fractionate with throughput of 

25 MMscf per day or greater.

2.Per this definition, we understand that if a booster processes 25 or more 

mmscf/day gas and generates condensate or produced water, it is 

considered Natural gas processing per this quoted definition. Please 

verify. Please note even this booster site does not generate J. T. Liquid 

or/and NGL.

Some facilities are designed solely to fractionate natural gas liquid streams. 

These facilities receive an inlet stream of natural gas liquids (not a gaseous 

form of natural gas) which does not contain methane. The facilities are 

designed to fractionate the liquids into individual products (ethane, 

propane, etc.) and do not produce a methane stream. The definition of 

Onshore Natural Gas Processing [98.230(a)(3)] states that this segment 

"separates and recovers NGLs and/or other non-methane gases and liquids 

from a stream of produced natural gas ". The definition of natural gas 

[according to 98.6] refers to "gases" – i.e., streams in a gaseous form 

("hydrocarbon and non-hydrocarbon gases [...] field production gas, 

process gas, and fuel gas"). Natural gas liquids are defined separately, and 

are not mentioned as the stream being processed in the definition of 

Onshore Natural Gas Processing. Therefore, please confirm that facilities 

designed to fractionate natural gas liquid streams are not included in the 

definition of Onshore Natural Gas Processing and are therefore not required 

to report under Subpart W.

Helpline
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Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

My environmental consulting firm works with a natural gas midstream 

company. This company does not own offshore or onshore production, 

underground natural gas storage, LNG storage, LNG import and export 

equipment, or natural gas distribution. They do own facilities that are 

potentially part of the onshore natural gas processing and onshore natural 

gas transmission compression industry segments. The specific definitions 

of these industry segments are as follows:

“Onshore natural gas processing. Natural gas processing separates and 

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

liquids from a stream of produced natural gas using equipment performing 

one or more of the following processes: 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 facility, whether inside or outside the processing facility fence. 

This source category does not include reporting of emissions from 

gathering lines and boosting stations. This source category includes: 

 i. All processing facilities that fractionate. 

 ii. All processing facilities that do not fractionate with 

throughput of 25 MMscf per day or greater.” [98.230(a)(3)]

“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 facilities in transmission pipelines to natural 

gas distribution pipelines or into storage. In addition, transmission 

compressor station may include equipment for liquids separation, natural 

gas dehydration, and tanks for the storage of water and hydrocarbon 

Helpline
12

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

liquids. Residue (sales) gas compression operated by natural gas processing 

facilities 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.” [98.230(a)(4)]

They own three natural gas processing facilities that do not fractionate. All 

three of these facilities have actual and potential natural gas throughputs 

below 25 MMscf per day; therefore, they are not included in the definition 

of the onshore natural gas processing industry segment. The 

determinations of if they are included in the onshore natural gas 

transmission compression industry segment are as follows.

• Gas Plant A does not have compression. This facility does not meet the 

definition of the onshore natural gas transmission compression industry 

segment and is not subject to Subpart W.

• Gas Plant B does have compression. The facility receives gas from 

production and delivers gas to an interstate transmission pipeline. Because 

the compression does not move gas to a distribution pipeline or into 

storage, it does not meet the definition of the onshore natural gas 

transmission compression industry segment and is not subject to Subpart 

W.

• Gas Plant C does have compression. The compression receives gas from 

production and discharges it to the inlet of the processing, and there is no 

residue (sales) gas compression at this facility. The plant outlet delivers 

gas to a distribution company. Because the compression moves gas to the 

inlet of the processing plant and not to a distribution pipeline or into 

storage, it does not meet the definition of the onshore natural gas 

transmission compression industry segment and is not subject to Subpart 

W.
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Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

This company also owns multiple natural gas compression facilities. All of

these facilities do not fractionate and have actual natural gas throughputs 

below 25 MMscf per day; therefore, they are not included in the definition 

of the onshore natural gas processing industry segment. The 

determinations of if they are included in the onshore natural gas 

transmission compression industry segment are as follows.

• Compressor Station 1: This station is on a pipeline system that receives 

gas from an interstate pipeline and delivers gas to a distribution company 

and end users upstream of a distribution company. Because the 

compression does not move gas from production or processing, it does not 

meet the definition of the onshore natural gas transmission compression 

industry segment and is not subject to Subpart W.

• Compressor Station 2: This station is on a pipeline system that receives 

gas from production and delivers gas to an interstate pipeline, a distribution 

company, and end users upstream of a distribution company. Therefore, it 

does meet the definition of the onshore natural gas transmission 

compression industry segment.

• Compressor Station 3: This station is on a pipeline system that receives 

gas from production and delivers gas to an interstate pipeline. Because the 

compression does not move gas to a distribution pipeline or into storage, it 

does not meet the definition of the onshore natural gas transmission 

compression industry segment and is not subject to Subpart W.

• Compressor Station 4: This station is on a pipeline system that receives 

gas from production and delivers gas to a processing facility. Because the 

compression does not move gas to a distribution pipeline or into storage, it 

does not meet the definition of the onshore natural gas transmission 

compression industry segment and is not subject to Subpart W.

• Compressor Station 5: This station is on a pipeline system that receives 

gas from production and delivers gas to a distribution company. Therefore, 

it does meet the definition of the onshore natural gas transmission 
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Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

compression industry segment.

• Compressor Station 6: This station is on a pipeline system that receives 

gas from production or another gathering pipeline and delivers gas to a 

processing facility. Because the compression does not move gas to a 

distribution pipeline or into storage, it does not meet the definition of the 

onshore natural gas transmission compression industry segment and is not 

subject to Subpart W.

• Compressor Station 7: This station is on a pipeline system that receives 

gas from production and delivers gas to a processing facility. Because the 

compression does not move gas to a distribution pipeline or into storage, it 

does not meet the definition of the onshore natural gas transmission 

compression industry segment and is not subject to Subpart W.

• Compressor Station 8: This station is on a pipeline system that receives 

gas from production and delivers gas to an interstate pipeline. Because the 

compression does not move gas to a distribution pipeline or into storage, it 

does not meet the definition of the onshore natural gas transmission 

compression industry segment and is not subject to Subpart W.

• Compressor Station 9: This station is on a pipeline system that receives 

gas from production and delivers gas to a processing facility. Because the 

compression does not move gas to a distribution pipeline or into storage, it 

does not meet the definition of the onshore natural gas transmission 

compression industry segment and is not subject to Subpart W.

• Compressor Station 10: This station is on a pipeline system that receives 

gas from an interstate pipeline and delivers gas to a distribution company 

and end users upstream of a distribution company. Because the 

compression does not move gas from production or processing, it does not 

meet the definition of the onshore natural gas transmission compression 

industry segment and is not subject to Subpart W.

The three facilities that are on pipeline systems that deliver gas to end 
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Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

users, Compressor Stations 1, 2, and 10, are not included in the definition 

of the natural gas distribution industry segment. The definition of this 

industry segment includes the statement, “This segment excludes customer 

meters and 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.” [98.230(a)(8)] The 

deliveries to end users on these systems are upstream of the local 

distribution company.

Compressor Stations 2 and 5 are required to report under Subpart W of the 

GHG reporting rule if their combined actual emissions from stationary fuel 

combustion units and Subpart W emissions sources exceed the 25,000 MT 

CO2e threshold.

Are these applicability determinations based on appropriate interpretations 

of the rule, and are the applicability determinations accurate?

Facility Definition: Subpart W defines onshore natural gas processing as 

"facilities that separate and recover natural gas liquids (NGLs) and/or other 

non-methane gases and liquids from a stream of produced natural gas 

using equipment performing one or more of the following processes: 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 source category does not include reporting of emissions 

from gathering lines and boosting stations. This source category includes: 

(1) all processing facilities that fractionate and (2) those that do not 

fractionate with throughput of 25 MMscf per day or greater." Would a 

compressor station that moves natural gas to transmission or distribution 

pipelines that has a dehydration unit for water removal (but does not 

recover NGLs) be considered a processing facility based on this definition?

Helpline
16

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

If the answer to the question above is "NO", then presumably this facility 

would fall under the definition of transmission compression. As such, 

would GHG emissions from the dehydrator vent be required to be included 

in the reporting for the station since this source type is not indicated under 

the natural gas transmission compression sector category?

3.Clarify that onshore 

natural gas processing 

includes residue gas 

compression equipment 

that is owned or operated 

by the plant.

Do compressors at the processing facility that push the natural gas at 

elevated pressure into the transmission lines fall under "processing" or 

"transmission"?

At least 2 

individual

Helpline

Facility Definition: Subpart W defines onshore natural gas processing as 

"facilities that separate and recover natural gas liquids (NGLs) and/or other 

non-methane gases and liquids from a stream of produced natural gas 

using equipment performing one or more of the following processes: 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 source category does not include reporting of emissions 

from gathering lines and boosting stations. This source category includes: 

(1) all processing facilities that fractionate and (2) those that do not 

fractionate with throughput of 25 MMscf per day or greater." Would a 

compressor station that moves natural gas to transmission or distribution 

pipelines that has a dehydration unit for water removal (but does not 

recover NGLs) be considered a processing facility based on this definition? 

If the answer to the question above is "NO", then presumably this facility 

would fall under the definition of transmission compression. As such, 

would GHG emissions from the dehydrator vent be required to be included 

in the reporting for the station since this source type is not indicated under 

Helpline
17

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

the natural gas transmission compression sector category?

Onshore Natural Gas Processing Industry Segment Definition. CEC/AXPC 

asserted that “[a]s presently drafted, the unclear and inconsistent final

provisions render the rule arbitrary and capricious and contrary to law.” 

CEC/AXPC further stated concerns with the definition for onshore natural 

gas processing industry segment definition and where the segment differs 

from onshore natural gas transmission industry segment, and from 

gathering lines and boosting stations. 

Trade 

Association 

Materials

4.Clarify in 98.232 (k) that 

stationary fuel 

combustion emission 

from onshore petroleum 

and natural gas 

production and natural 

gas distribution are not 

reported in Subpart C. 

Will the combustion operations not covered by Subpart W have to report 

under Subpart C?

At least 1 

individual

Helpline

5.Addition of parameter T

in Equation W-1 to 

account for the total time 

the pumps are 

operational.

Pneumatic devices. I suggest that EPA add a size threshold for intermittent 

natural gas pneumatic devices that will be required to report under 

98.233(a). The gas well sites that we visited were very simple sites. One of 

the typical configurations included a well-head with plunger which fed to a 

10 foot tall by 2.5 foot diameter high pressure separator (or to a high 

pressure and then low pressure separator). The separator feeds liquids to a 

400 barrel hydrocarbon liquid tank and a 400 barrel water tank. The gas is 

sent to the sales line. Because there is no electrical supply to these well 

pads, natural gas pneumatics are used on the control boxes for equipment 

with moving parts. These pneumatic devices range from tiny 

(approximately 5" in diameter and 7" tall) to slightly larger disc-shaped 

devices (approximately 12" in diameter). I can provide photos if those 

would be helpful. Each 3-phase separator has 2 pneumatic devices to 

control the liquid level dump switches. Each 2-phase separator has 1 

At least 1 

individual

Helpline
18

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

pneumatic valve on the liquid level dump. Each plunger device has two 

pneumatic devices, and each well-head has one emergency shut-off 

pneumatic device. For all of these tiny devices, the venting time is very 

short and the vented volume is very small. The pumper estimated 

approximately a half cubic foot of gas might be released on the separator 

level dump, and this may only happen once every few days. (He 

demonstrated the actuation of the device and the pneumatic made a short 

whoosh and was done.) The plunger may operate several times per day but 

the pneumatic is very small and will vent for approximately 5 seconds. The 

emergency shut-off devices rarely operate. For all of these types of 

intermittent pneumatic devices, the provided emission factor 17.4 

scf/hour/device will grossly over-estimate emissions, especially given the 

equation requires application of the emission factor to 8,760 hours per year. 

Are these small devices meant to be included in the pneumatic device 

counts?

There are also pneumatic pumps that are used very rarely to pump out the 

tank bottom contents. These are only used occasionally and the application 

of the provided emission factor of 13.3 scf/hour/pump over the entire year 

will grossly overestimate the emissions from these devices that operate 

possibly only once per year. Are these pumps meant to be included in the 

pneumatic pump counts?

6.Clarify the definition of 

Count in Equation W-1.

In equation W-1 in 98.233.a, Count is defined as determined in (a)(1) of 

this section. I believe EPA intended to include (a)(2) in that definition of 

count. Is that correct?

At least 1 

individual

Helpline

7.Clarify in 98.233 (a) that 

all applicable industry 

segments can determine 

the type of pneumatic 

Pneumatic Devices. CEC/AXPC asserted that “EPA has not given 

sufficient consideration to the burden imposed by requiring that the bleed 

rate of each device be determined in order to count and classify the 

devices.”

At least 2 

individuals

Trade 

Association 

Material
19

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

device using engineering 

estimate.

API asserted that “[a]lthough EPA has provided emission factors in Table 

W-1A that apply to continuous high-bleed, continuous low-bleed, and 

intermittent bleed pneumatic devices, EPA has not provided guidance on 

how to classify pneumatic devices according to these three categories.”

Trade 

Association 

Materials

8.Addition of parameter T

in Equation W-2 to 

account for the total time 

the pumps are 

operational.

Under §98.233(c), how are pneumatic pumps that operate only part of the 

year assessed? [We] believes it unfair to blankly apply the emission factors 

in Table W-1A to pumps that do not operate all year. Can the "24*365" 

component of Equation W-2 be modified by the reporter to more accurately 

reflect operating conditions?

At least 1 

individual

Helpline

Pneumatic devices. I suggest that EPA add a size threshold for intermittent 

natural gas pneumatic devices that will be required to report under 

98.233(a). The gas well sites that we visited were very simple sites. One of 

the typical configurations included a well-head with plunger which fed to a 

10 foot tall by 2.5 foot diameter high pressure separator (or to a high 

pressure and then low pressure separator). The separator feeds liquids to a 

400 barrel hydrocarbon liquid tank and a 400 barrel water tank. The gas is 

sent to the sales line. Because there is no electrical supply to these well 

pads, natural gas pneumatics are used on the control boxes for equipment 

with moving parts. These pneumatic devices range from tiny 

(approximately 5" in diameter and 7" tall) to slightly larger disc-shaped 

devices (approximately 12" in diameter). I can provide photos if those 

would be helpful. Each 3-phase separator has 2 pneumatic devices to 

control the liquid level dump switches. Each 2-phase separator has 1 

pneumatic valve on the liquid level dump. Each plunger device has two 

pneumatic devices, and each well-head has one emergency shut-off 

pneumatic device. For all of these tiny devices, the venting time is very 

short and the vented volume is very small. The pumper estimated 

approximately a half cubic foot of gas might be released on the separator 
20

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

level dump, and this may only happen once every few days. (He 

demonstrated the actuation of the device and the pneumatic made a short 

whoosh and was done.) The plunger may operate several times per day but 

the pneumatic is very small and will vent for approximately 5 seconds. The 

emergency shut-off devices rarely operate. For all of these types of 

intermittent pneumatic devices, the provided emission factor 17.4 

scf/hour/device will grossly over-estimate emissions, especially given the 

equation requires application of the emission factor to 8,760 hours per year. 

Are these small devices meant to be included in the pneumatic device 

counts?

There are also pneumatic pumps that are used very rarely to pump out the 

tank bottom contents. These are only used occasionally and the application 

of the provided emission factor of 13.3 scf/hour/pump over the entire year 

will grossly overestimate the emissions from these devices that operate 

possibly only once per year. Are these pumps meant to be included in the 

pneumatic pump counts?
21

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

9.Amend Equation W-4 to 

eliminate error in GHG 

estimate due to the 

approximation in 

calculation method and 

subsequent adjustment in 

parameter definition.

Regarding Equation W-4, for Method 3 for AGR unit CO2 emissions:

When outlet NG volume rather than inlet NG volume is measured and used 

as the input to this equation, the accuracy of W-4 depends on the outlet 

volume being very close to the inlet volume. This is the case for 

conventional gas, but it becomes increasingly problematic with high CO2 

content in the inlet gas, such as with coalbed methane or possibly in any 

EOR operation where the CO2 is not captured and reinjected. Although a 

delta(CO2 conc.) of 0.1 (12% in, 2% out) results in an error of only -1% in 

the emissions estimate, we don't see any need to accept this error when 

simply specifying a different equation for this case would give theoretically 

accurate values. Furthermore, much higher errors could result if the inlet 

concentration was much higher than 10%, perhaps in some situation you 

did not anticipate.

The attached spreadsheet shows how the percent error varies with 

delta(CO2 conc.), and also provides a recommended equation for the case 

where only outlet NG volume is measured. The WCI Reporting Taskgroup 

would like to allow outlet-only measurement as an option, but we are 

reluctant to do so if Eq. W-4 would be used for this situation.

Perhaps EPA can address this issue in some future amendment to Subpart 

W.

Helpline
22

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

10. Clarify that use of 

stripping gas is not 

limited to natural gas 

and can be any gas.

This question relates to Subpart W, glycol dehydrator stripping gas.

The rule requests:

98.233(e)(1)(vii) Use of stripping natural gas

98.236(c)(4)(i)(C) Whether stripper gas is used in glycol dehydrator

Is EPA looking for whether stripping gas is used (which could be dry gas, 

flash gas, or nitrogen)? Or is EPA looking for whether stripping *natural* 

gas is used? If it's the latter, does EPA consider dehydrator flash gas to be 

natural gas (as flash gas does not generally meet the 98.6 definition of 

natural gas)?

In general, I'm trying to understand if this data element will be a "Yes/No" 

option, or if it will be a "No/Dry Gas/Flash Gas/Nitrogen" option.

At least 1 

individual

Helpline

11. Clarify 98.233 (e)(6) by 

stating that 98.233 (u) 

and 98.233 (v) must be 

used to determine CH4

and CO2 mass emissions. 

This question relates to Subpart W calculation methodology for dehydrator 

vents.

For dehydrators >=0.4 mmcfd, Calculation Methodology 1 98.233(e)(1) 

specifies that software that "speciates CH4 and CO2 emissions" shall be 

used.

For dehydrators <0.4 mmcfd, Calculation Methodology 2 98.233(e)(2) 

required equation W-5 which calculates speciated emissions only.

However, 98.233(e)(6) says "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." Is 98.233(e)(6) 

supposed to be referring to dehydrators that use desiccant only? If so, the 

rule should be modified to clarify that this is the intent. Otherwise, the rule 

does not provide a method for estimating volumetric natural gas emissions, 

At least 1 

individual

Helpline
23

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

particularly for dehydrators with <0.4 mmcfd throughput.

12. Addition of Equation 

W-11C to determine 

sonic versus sub-sonic 

flow

Separate calculations for Subsonic and supersonic flow when both happen 

during a single completion. API asserted that “[t]he proposed rule did not 

include a requirement that well completions have separate calculations for 

subsonic and supersonic flow when both occur during a single completion. 

The final rule adds this requirement, which is not technically possible.”

At least 1 

individual

Trade 

Association 

Materials

13. Clarify in paragraph 

98.233 (1)(i)(A) that 

vent average flow rate 

must be determined for 

each tubing diameter 

grouping and pressure 

grouping.

Mapping Wells to Fields. CEC/AXPC asserted that “EPA has not clarified 

how reporting entities are supposed to map wells to a particular „field.‟” 

Also, CEC/AXPC asserted that “[w]ithout sufficient clarity regarding what 

wells are in a particular field, it is difficult for covered sources to know 

with certainty what gas composition is considered representative for each 

well.”

At least 1 

individual

Trade 

Association 

Materials

14. 11. Clarification to 

Equations W-8 and W9 to account for actual 

versus standard 

condition and annual 

versus event based 

calculations

There appear to be several issues with equations W-8 and W-9.

The equations include a pressure correction, but not a temperature 

correction

The emission term that results from the equations is labeled as actual cubic 

feet, but the conversions really result in standard cubic feet due to the 

pressure correction

The equations then reference equation W-33 which converts from actual to 

standard conditions, essentially double correcting for pressure.

The units in the second part of the equations are not clear. If HR is an 

annual value (sales flow rate/hr per year), than subtracting 1 hour or 30 

minutes from annual hours is meaningless. If HR is on an event basis or 

daily basis, then the equations are missing a summation.

Please correct or clarify the units for these equations.

At least 1 

individual

Helpline

I am finding errors in the EPA's Equation W-9 to calculate emissions from 
24

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

each well venting to the atmosphere for liquids unloading w/ plunger lift 

assist. These same errors are also in Equation W-8. They are hard to 

explain, but "EPA's technical experts" should be able to follow the 

explanations below.

1. It states that the answer is the gas emissions at actual conditions, in cubic 

feet per year. This is incorrect. The factor of 0.00037 that is used includes 

dividing by 14.7 psia, which converts the volume to standard pressure. The 

first part of the equation calculates the volume of the tubing, but then it 

multiplies by the sales pressure and divides by 14.7 (built in the 0.00037 

factor). This takes the volume in the tubing and converts it to standard 

pressure. To get it to standard conditions, only the temperature needs to be 

considered since your equation already calculates the gas volume at 

standard pressure. Also, the second half of your equation (which also has 

errors that I discuss below) uses sales flow rate which, of course, is in 

standard conditions already --- so the resulting answer is obviously going to 

be in standard conditions.

2. The first part of the equation calculates the tubing volume and converts it 

to standard pressure, as discussed above. This result is then multiplied by 

the number of vents per year to give a volume vented for the year. Then we 

are to add the second part of the equation to that yearly volume. The 

problem is the second part of the equation is (or should be) calculating an 

extra volume per venting cycle, not a yearly volume. I am assuming that 

"HR" is the hours left open during a venting cycle, because it would not 

make sense if that was in hours per year. The EPA's assumptions (which I 

don't agree with) are that if a well on plunger lift vents to atmosphere 

during one of its plunger cycles, it vents the entire volume of the tubing in a 

half hour, then any venting over a half hour, the well is venting at the sales 

flow rate. The problem is the equation that the EPA provided does not 
25

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

calculate this correctly.

15. Changing requirements 

to be applicable to subbasin category and well 

type (horizontal vs. 

vertical) combination.

Mapping Wells to Fields. CEC/AXPC asserted that “EPA has not clarified

how reporting entities are supposed to map wells to a particular „field.‟” 

Also, CEC/AXPC asserted that “[w]ithout sufficient clarity regarding what 

wells are in a particular field, it is difficult for covered sources to know 

with certainty what gas composition is considered representative for each 

well.”

At least 1 

individual

Trade 

Association 

Materials

16. 12. Clarify that the 

requirements set forth 

in 98.233 (g)(3) and 

98.233 (g)(5) are 

applicable to both 

completions and 

workovers from 

hydraulic fracturing 

The calculation methodology for gas well venting during completions and 

workovers from hydraulic fracturing [98.233(g)] allows for the subtraction 

of gas recovered to sales by use of the variable SG in Equation W-10. 

However, 98.233(g)(3) refers to only the volume of "completion gas", not 

the volume of "completion or workover gas". Similarly, 98.233(g)(5)(i) 

notes that the variable SG is for the magnitude of emissions captured using 

"reduced emissions completions" not "reduced emissions completions or 

workovers". 

As both workovers and completions may involve reduced emissions 

approaches, please confirm that the variable SG is to represent the volume 

of gas routed to sales during both workovers and completions.

At least 1 Helpline

17. Clarify the parameter 

definitions for f, Vp, and 

Tp in Equation W-13 to 

make it applicable to a 

sub-basin category 

instead of field.

Mapping Wells to Fields. CEC/AXPC asserted that “EPA has not clarified 

how reporting entities are supposed to map wells to a particular „field.‟” 

Also, CEC/AXPC asserted that “[w]ithout sufficient clarity regarding what 

wells are in a particular field, it is difficult for covered sources to know 

with certainty what gas composition is considered representative for each 

well.”

At least 2

individual

Trade 

Association 

Materials

Field level reporting for onshore petroleum and natural gas production. 

API asserts that “[t]his level of reporting is problematic when applied to 

new requirements of the final rule. For the same reasons, it remains 

problematic when applied to those requirements in the proposed rule that 

Trade 

Association 

Materials
26

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

remain in the final rule.”

18. Clarify that emergency 

blowdowns are 

included in the rule.

(i) Blowdown vent stacks. 

Clarify “exempt volumes; events to include (i.e., “significant” 

blowdowns for maintenance or safety), and add another calc 

(operator selects calc to use) where events are calculated and 

summed. 

Calculate CO2 and CH4 blowdown vent stack emissions from 

depressurizing equipment to the atmosphere to reduce system pressure 

for planned or emergency shutdowns or to take equipment out of 

service for maintenance (excluding depressurizing to a flare, overpressure relief, operating pressure control venting and blowdown of nonGHG gases; desiccant dehydrator blowdown venting before reloading is 

covered in paragraph (e)(5) of this section) as follows: 

Trade 

Association 

Materials

19. Addition of Equation 

W-14B to allow 

emission to be 

calculated on a per 

occurrence basis and 

allow a correction for 

blowdowns that are not 

brought down to 

atmospheric pressure.in 

w

N

i a i s

s a i a f i

s n v i

T P

T P P

E V

1 ,

,0, , ,

, ,

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 blowdowns in the calendar year. 

Vv,i = Total volume of blowdown equipment chambers (including 

pipelines, compressors and vessels) in cubic feet. 

Ts = Temperature at standard conditions ( °F). 

Ta,i = Temperature at actual conditions (estimated) for event “i” in 

Trade 

Association 

materials
27

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

the blowdown chamber (°F). 

Ps = Absolute pressure at standard conditions (psia). 

Pa,0,i = Absolute pressure at actual conditions at the start of event “i" 

in the blowdown chamber (psia). 

Pa,f,i = Absolute pressure of natural gas at actual conditions at the end 

of event “i" in the blowdown chamber (psia) ((if the 

equipment is purged using non-GHG gases then Pa,f,i = 0).

20. Amend 98.233 (k) by 

allowing reporters to 

measure the emission 

from the tank vent 

directly instead of 

monitoring for emission 

using an optical gas 

imaging device

(k) Transmission storage tanks. 

Correct reference to flaring in intro, add monitoring method 

flexibility, and delete reference to flaring calculation (broadly 

addressed in §98.232(j) and not needed in this section) 

For condensate storage tanks, either water or hydrocarbon, without vapor 

recovery or thermal control devices in onshore natural gas transmission 

compression facilities calculate CH4, and 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. 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 estimate quantify

emissions: 

Trade 

Association 

materials
28

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

(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 vent stack. If the vent is 

directly measured for five minutes under section (1) to detect 

continuous leakage, this serves as the measurement. If a leak 

of 3.1 SCF per hour or greater is measured, a leak is detected 

and must be reported. 

(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). 

(3)(iii) Calculate both CH4 and CO2 volumetric and mass 

emissions using calculations in (u) and (v) of this section, and 

using Use the appropriate gas composition in paragraph (u)(2)(iii) of 

this section or the gas composition allowed in §98.232(m). 

(4)(3) If the leaking dump valve(s) is repaired 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 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. 
29

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

(ii) Use the calculation methodology of flare stacks in paragraph 

(n) of this section to determine storage tank emissions from the 

flare.

21. Clarify the GHG mole 

percentage of the 

natural gas liquids 

should be used for 

onshore natural gas 

processing plants that 

solely fractionate a 

liquid stream.

EPA may not be aware that facilities which are designed solely to 

fractionate a liquid stream will not have a de-methanizer. However, this 

same facility may flare natural gas. Therefore, IF: 

1) facilities which receive a natural gas liquid stream for fractionation 

are regulated under the Gas Processing Segment of Subpart W (see 

email "Question on Natural Gas Liquids Fractionators" submitted by 

Stephanie Jones of URS to ghgmrr@epa.gov on 11/24/10), AND 

2) the facility does not have a continuous gas composition analyzer on 

the gas to the flare, AND 

3) measurements of the flare gas which are not made with a continuous 

GC analyzer cannot be used for compliance with 98.233(n)(2)(ii) (see 

email "Question on Alternative Composition Sampling for Flare 

Stacks" submitted by Stephanie Jones of URS to ghgmrr@epa.gov on 

11/19/10), 

Please confirm that engineering estimates may be used in this situation to 

determine the flare gas composition under 98.233(n)(2)(ii) when the stream 

going to the flare is natural gas.

At least 1 

individual

Helpline

22. Clarify that GHGi for 

onshore natural gas 

processing does not 

need to be determined 

in Equation W-31 

because 98.233 (r) is 

not applicable to that 

source category

98.236(c)(15)(ii)(A). The source categories in 98.230(a)(3) and (a)(4) are 

listed under this reporting section, but are not required to use population 

count calculations, as far as I can tell. Please confirm.

At least 1 

individual

Helpline

I have the following questions about the parameter "GHGi" in Subpart W 

for pneumatic devices, pneumatic pumps, and equipment leaks:

Question -For equipment leaks, how and at what frequency should GHGi in 

Equation W-31 be determined for onshore petroleum and natural gas 
30

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

production and processing facilities? Note that the equation does not refer 

to 98.233(u), so it is not clear how GHGi should be determined and at what 

frequency.

23. Amend Equation W-32 

by adding a conversion 

factor to make it hourly 

emissions.

I am developing a spreadsheet for APGA members to perform subpart W 

calculations for natural gas distribution systems and found what I think is 

an error in the equations for estimating fugitive emissions from noncustody transfer gate stations; equations W-31 and W-32.

Equation W-31 is as follows: Es,i = Counts * EFs *GHGi *Ts

EFs is the emission factor in scf/hr and Ts is the number of hours of 

operation during the calendar year.

For non custody transfer gate stations EFs is calculated using Equation 32 

which is EF = Sum (Es,i/Count) (Eq. W-32)

Where Es,i is the annual estimated emissions from custody transfer gate 

station and count is the number of meter runs.

I think EPA‟s intent was to assume fugitive emissions from non-custody 

transfer gate stations was the same as fugitive emissions from custody 

transfer gate stations, which isn‟t a bad assumption, but equation W-32 

produces an emission factor, EFs, that is the average annual fugitive 

emissions per meter run at custody transfer gate stations rather than an 

hourly emission factor required by Equation W-31. As a result, the 

estimated emissions from non-custody transfer gate stations are 8,760 times 

greater than estimated emissions from custody transfer gate

stations.

At least 2 

individual

Helpline
31

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

Equation W-32 should be EF = Sum (Es,i/(Count*Ts)) so that the 

calculated emission factor is an hourly emission factor rather than an 

annual emission factor.

This question pertains to the calculation method for an LDC facility's noncustody transfer gate stations. In the rule, equations W-31 and W-32 are to 

be utilized to calculate emissions from these sources. The EF as calculated 

in W-32 has units of scf/meter-year. If the vast majority of a company's 

non-custody transfer gate stations which are above grade are purely 

regulating stations (ie no meters), then are the emissions from these stations 

required to be reported? In the manner in which the equations are written 

now, it suggests that emissions from these sources are not covered. Please 

confirm or explain.

New emission factor formulas are confusing or contain math errors that 

vastly inflate emission estimates. AGA asserted that the “[t]he new 

emissions factor equations W-30, W-31 and W-32 in the final rule are 

confusing. Since these formulas were not included in the proposed rule, 

AGA did not have an opportunity to comment on them.” 

Trade 

Association 

Materials

Errors in Calculations. Southwest Gas Corporation asserted that the 

USEPA published errors in equations in 40 CFR 98.233, namely equation 

W-32. 

Trade 

Association 

Materials

24. Clarify how 

meters/piping should be 

counted in Equation W32.

When using Table W-1B to determine counts for major onshore natural gas 

production equipment, how would a facility determine counts of 

“meters/piping”? Specifically, how should “piping” be counted?

At least 3 

individuals

Helpline

Under subpart W equipment leaks for onshore production, how do we 

apply the "meters/piping" count? Is there one of these "meter/piping" 

counts per sales flow meter, or one per site (such as one per well pad site 

and one per central facility)?

Helpline

Please clarify how "meters/piping" are to be quantified in order to apply the 

default average component counts in Table W-1B. 

Helpline
32

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

• Is there simply one "meters/piping" count per well pad location? 

• Does a well pad with only a wellhead (no separator, no tanks) still get a 

"meters/piping" count because there is piping from the wellhead? 

• Is this count only for piping associated with meters, and if so does any 

amount of piping associated with a single meter count as one "equipment" 

unit? 

• Does a particular length of piping count as one unit of "equipment"? 

For underground natural gas storage we are trying to determine how to 

calculate equipment leaks as specified in 98.232(f)(5). Pursuant to 

98.233(r) we are allowed to use Equation W-31. However, for the "Count" 

in equation W-31 it refers to using Tables W-1B and W-1C, but these 

tables are for Default Average Components Counts for Onshore Natural 

Gas Production and Major Crude Oil Production Equipment, respectively. 

Do we use these tables for underground natural gas storage?

Helpline

Non custody transfer city gate station terminology. AGA asserted that 

“[s]everal provisions in the Subpart W rule and preamble seem to imply 

that a „non-custody-transfer city gate station‟ will always have a meter.”

Trade 

Association 

Materials

25. Clarify the paragraphs 

98.233 (t)(1) and (t)(2)

(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 

converting actual temperature and pressure of natural gas emissions to 

standard temperature and pressure of natural gas using actual natural 

gas emissions temperature and pressure, and Equation W–33 of this

section.

Trade 

Association 

Materials
33

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

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 ( °F). 

Ta = Temperature at actual emission conditions ( °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 actual temperature and pressure of GHG emissions to standard 

temperature and pressure using actual GHG emissions temperature and 

pressure, and Equation W–34 of this section.

Where: 

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 ( °F). 

Ta = Temperature at actual emission conditions ( °F). 

Ps = Absolute pressure at standard conditions (psia). 

Pa = Absolute pressure at actual conditions (psia).
34

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

26. Clarify the introductory 

paragraph to 98.233 (u)

(u) GHG volumetric emissions. Calculate GHG volumetric emissions at 

standard conditions as specified in paragraphs (u)(1) and (2) of this section, 

with mole fraction of GHGs in the natural gas determined by 

engineering estimate based on best available data unless otherwise 

specified. 

(1) Estimate CH4and CO2emissions from natural gas emissions using 

Equation W–35 of this section.

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. 

Mi = Mole fraction of GHGiin the natural gas.

Trade 

Association 

Materials

27. Clarify that an annual 

average gas 

composition based on 

best available analyses 

in each of the sub-basin 

categories can be used 

if a gas composition 

analyzer is not available

Use of gas composition based on available sample analysis for reporters 

without continuous gas composition analyzer. API asserts that “EPA 

should resolve the ambiguity created by the current language.”

Trade 

Association 

Materials

28. Add default gas 

compositions for 

onshore natural gas 

transmission, 

underground natural gas 

storage, LNG storage, 

LNG import and export 

(2) For Equation W–35 of this section, the mole fraction, Mi, shall be 

the annual average mole fraction for each 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, 

Trade 

Association 

Materials
35

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

facilities, and natural 

gas distribution 

facilities

you must use these values for determining the mole fraction. If 

you do not have a continuous gas composition analyzer, then you 

must use your most recent gas composition based on available 

sample analysis of the field. 

(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 demethanizer overhead or dew point control for onshore natural gas 

processing facilities. 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 or the composition in §98.232(m)(1). 

(iv) GHG mole fraction in natural gas stored in underground 

natural gas storage facilities or the composition in 

§98.232(m)(1). 

(v) GHG mole fraction in natural gas stored in LNG storage 

facilities or the composition in §98.232(m)(1).

(vi) GHG mole fraction in natural gas stored in LNG import and 

export facilities.
36

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

(vii) GHG mole fraction in local distribution pipeline natural gas 

that passes through the facility for natural gas distribution 

facilities or the composition in §98.232(m)(1).

29. Clarify the introductory 

paragraph to 98.233 (v)

(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.

Trade 

Association 

Materials

30. Clarify the definition of 

Masss,i, Es,i, and by i

adding N2O 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. 

ρ i = Density of GHG i. Use 0.0538 kg/ft3for CO2 and N2O, and 

0.0196 kg/ft3for CH4 at 68 °F and 14.7 psia or 0.0530 kg/ft3

for CO2 and N2O, and 0.0193 kg/ft3for CH4 at 60°F and 14.7 

psia. 

GWP = Global warming potential, 1 for CO2, 21 for CH4, and 310 for 

N2O.

Trade 

Association 

Materials

31. Clarify the 

requirements of 

calibrated bagging in 

98.234 (c).

(c) Use calibrated bags (also known as vent bags) only where the emissions 

are at near-atmospheric pressures and below the maximum temperature 

specified by the vent bag manufacturer such that it the bag is safe to 

handle. and can capture all the emissions, below the maximum temperature 

specified by the vent bag manufacturer, and The bag must be of sufficient 

size that the entire emissions volume can be encompassed for 

measurement.

Trade 

Association 

Materials
37

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

32. Clarify that 98.233 (t) 

can be used to convert 

emissions at actual 

conditions to standard 

conditions for high 

volume samplers.

(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 anti-static wraps or other aids to capture all emissions 

without violating operating requirements as provided in the instrument 

manufacturer's manual.

(3) Estimate natural gas volumetric emissions at standard 

conditions using calculations in §98.233(t). 

(34) Estimate CH4 and CO2 volumetric and mass emissions from 

volumetric natural gas emissions using the calculations in §98.233(u) 

and (v). 

(45) 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.

Trade 

Association 

materials
38

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

33. Clarify that emissions 

from gas routed flares 

must be reported 

separately from 

emissions vented 

directly to the 

atmosphere throughout 

98.236(c) and in the 

introductory paragraph 

to 98.236.

Well testing venting and flaring clarification. CEC/AXPC asserted that 

“[t]he final rule is unclear regarding the requirement to report emissions 

from well testing venting and flaring.”

At least 2 

individuals

Trade 

Association 

Materials

34. 98.236(c)(11)(iii). This only requires reporting of the flared gas. No 

reporting of vented gas?

Helpline

35. Clarify the level of 

reporting (i.e. facility 

level, by equipment) in 

98.236 (c).

Number of plunger lifts and average casing diameter in inches. API 

asserted that “[t]he final rule adds 40 CFR 98.236(c)(5) requirements to 

report the number of plunger lifts and average casing diameter in inches by 

field. The difficulty with these additions is not with the requirement for 

counting plunger lifts and noting casing diameter, but that reporting must 

take place at the field level.”

At least 1 

individual

Trade 

Association 

Material

Basin level reporting for onshore petroleum and natural gas production. 

API asserted that “[t]his broad definition of onshore production facility is 

impractical. Subpart W imposes reporting requirements on over 22,000 

entities operating hundreds of thousands of wells and millions of pieces of 

equipment scattered over hundreds of thousands of square miles.”

Trade 

Association 

Material
39

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

36. Amend the definition of 

“facility with respect to 

natural gas distribution 

for purposes of this 

subpart and subpart A”.

How should M&R Stations that are jointly owned, in whole or in part, 

between an LDC and an interstate pipeline company (e.g. Transco, Texas 

Eastern) be treated in terms of Subpart W reporting by the LDC? It seems 

reasonable that the LDC is only responsible for reporting for the affected 

equipment that the LDC owns and operates, and that the interstate pipeline 

company is responsible for reporting for the affected equipment that the 

LDC owns and operates.

At least 1 

individual

Helpline

37. Provide a definition for 

associated with a single 

well-pad

What does “associated with a well pad and CO2 EOR operations” mean in 

the definition of a facility (98.238)?

a. For example are gathering booster compressors associated with a 

well pad?

b. b. How do you handle equipment (dehydrators) located on 

individual well-pads but owned/operated by a gathering/collection 

3rd party company and paid as part of a “tolling” agreement with a 

$/mcf gathering fee?

At least 3 

individual

Helpline

Subpart W repeatedly refers to sources of emissions "on a well pad or 

associated with a well pad". But neither Subpart W nor Subpart A include 

definitions for the terms "well pad" or "associated with a well pad".

Assume an oil and gas production facility consists of, say, a 1000 acre area 

throughout which 50 or more wells (well pads?) are scattered, but with no 

equipment located at the wells. The wells produce via pipelines to one or 

more central sites where produced fluids from the wells are processed (for 

sale, re-injection, etc.). The central sites consist of separators, combustion 

equipment, storage tanks, and other process equipment, but no wells or 

"well pads". Is the equipment located at the central processing sites 

considered equipment that is "associated with a well pad" and, thus, 

included in the definition of "facility" under Subpart W?

Helpline
40

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

In the definition of an Onshore Petroleum and Natural Gas Production 

facility, it says....."on a well pad or associated with a well pad (including 

compressors, generators, or storage facilities)". Can you more specifically 

define "associated with a well pad"? What we need to know is if that means 

the "included" equipment is only applicable if it is AT that exact well pad 

location OR does it mean that "included" equipment is applicable if it is in 

any way connected to the production of the gas pumped from the well pad 

(even if it is NOT located at the same location as the well pad).

Helpline

I'm trying to understand the boundaries of our facility under Subpart W. 

Our project consists of 2 gravel pads separated by 8 miles. 

One pad (well pad) contains multiple wells, a drilling rig, and other support 

equipment. Three-phase production (oil/gas/water) from the well pad is 

transported 8 miles via flowlines to the second pad. 

The second pad (tie-in pad) provides power and other utilities to the well 

pad and is a tie-in point to third-party facilities. The tie-in pad contains 

metering equipment (including a production separator), power generation, 

gas compression for natural gas EOR injection (separate from the 

production stream), and other support equipment. Processing of the threephase production is done entirely by a third party several miles downstream 

of the tie-in pad.

My interpretation of Subpart W is that the well pad is an onshore petroleum 

and natural gas production facility but that the tie-in pad doesn't fall under 

any of the categories. The well pad should be evaluated for applicability 

under Subparts C and W and, separately, the tie-in pad for applicability 

under Subpart C.

Helpline
41

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

Please let me know if I've understood the rule correctly or if you need any 

additional information.

Definitions to Industry Categories. API asserted that the “[a]ltered final 

rule creates ambiguity as to whether certain facilities are included in the 

production category, excluded as gathering or booster stations, or included 

under the gas processing category.”

Trade 

Association 

Materials

38. Provide a definition of 

transmissiondistribution transfer 

station

Please provide a definition of "custody transfer city gate" and "non-custody 

transfer city gate station" as used in 98.232(i)(1) and (2). These definitions 

should be incorporated into the rule.

At least 4 

individuals

Helpline

For local distribution companies, please verify that emissions do not need 

to be calculated and reported for above-ground non-custody transfer city 

gate stations that are solely defined as regulating stations and do not 

contain any metered runs.

Helpline

Please explain the difference between a custody and non-custody transfer 

city gate station. Thank you.

Helpline

If I have a distribution "facility" that does not own or operate any above 

ground M&R at custody transfer city gate stations, how do I calculate the 

EF required for above ground M&R at non-custody transfer city gate 

stations? There is no other option for calculating emissions for this 

emission source.

Helpline

Custody transfer city gate station terminology. AGA asserted that the term 

“custody transfer city gate station” in subpart W was unclear and needed 

clarification. 

Trade 

Association 

Materials

Terms in Subpart W. Petitioner asserted that “[t]he USEPA‟s final rule 

fails to provide clear definitions that can be used uniformly throughout the 

natural gas distribution industry.”

Trade 

Association 

Materials

39. Provide a definition of 

metering-regulating 

station

Please provide a definition of "custody transfer city gate" and "non-custody 

transfer city gate station" as used in 98.232(i)(1) and (2). These definitions 

should be incorporated into the rule.

At least 3 

individuals

Helpline
42

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

For local distribution companies, please verify that emissions do not need 

to be calculated and reported for above-ground non-custody transfer city 

gate stations that are solely defined as regulating stations and do not 

contain any metered runs.

Helpline

If I have a distribution "facility" that does not own or operate any above 

ground M&R at custody transfer city gate stations, how do I calculate the 

EF required for above ground M&R at non-custody transfer city gate 

stations? There is no other option for calculating emissions for this 

emission source.

Helpline

Terms in Subpart W. Petitioner asserted that “[t]he USEPA‟s final rule 

fails to provide clear definitions that can be used uniformly throughout the 

natural gas distribution industry.”

Trade 

Association 

Materials

40. Provide definition of 

“natural gas”.

Pipeline Quality Natural Gas. CEC/AXPC asserted that “[t]here is not 

a clear and unambiguous definition in the final rule for „pipeline 

quality‟ natural gas.”

Trade 

Association 

Materials

41. Provide a definition of 

the transmission 

pipeline

Gathering and Boosting are not defined, leaving a lot up to interpretation. 

'Transmission pipeline' is defined rather loosely. I have a list of 20 small 

compressor stations that must be classified with very little guidance. If the 

goal is to capture only very large compressor stations introducing gas into 

interstate pipelines, that term should be used or minimum pipeline 

pressures and diameters should be named. Does the term 'cross country 

pipeline' exclude intrastate pipelines? The natural gas collection pipeline 

network is extensive and complicated in some parts of the country. Tiny 

boosting compressor stations not related to the very biggest of transmission 

pipelines should not have to go to the expense of performing the optical 

leak detection and flow rate sampling exercises. Alternately, a compressor 

engine horsepower size cutoff should be named. (Or total aggregate 

compressor horsepower at a single facility.)

At least 2 

individuals

Helpline
43

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

The definition of the onshore natural gas transmission compression 

includes "any stationary combustion of compressors that move natural gas 

at elevated pressure from production fields or natural gas processing 

facilities in transmission pipelines to natural gas distribution pipelines or 

into storage." How does EPA currently define transmission pipelines? Is 

this definition consistent with how any other federal agencies define 

transmission? For example, DOT defines a transmission line as follows: 

Transmission line means a pipeline, other than a gathering line, that: (1) 

Transports gas from a gathering line or storage facility to a distribution 

center, storage facility, or large volume customer that is not down-stream 

from a distribution center; (2) operates at a hoop stress of 20 percent or 

more of SMYS; or (3) transports gas within a storage field.

Helpline

Excluding Boosting Stations. CEC/AXPC asserted that “[t]he final rule 

fails to distinguish between a boosting station, which is exempt, and an 

„onshore natural gas transmission compression facility‟ which must report 

under the rule.”

Trade 

Association 

Materials

Onshore Natural Gas Transmission Compression Industry Segment 

Definition. CEC/AXPC asserted that “[a]s presently drafted, the unclear 

and inconsistent final provisions render the rule arbitrary and capricious 

and contrary to law.” And “The term „onshore natural gas transmission 

compression‟ means a stationary combination of compressors that move 

natural gas at elevated pressure from production fields or natural gas 

processing facilities in transmission pipelines or into storage. 40 C.F.R. 

§98.230(a)(4). A transmission compressor station can include equipment 

to separate liquids or dehydrate natural gas Id. However, according to the 

final rule this source category does not include gathering lines and boosting 

stations.”

Trade 

Association 

Materials

42. Provide a definition for 

tubing systems

Section 98.233(r) describes the GHG calculation methodology for 

equipment leaks for onshore oil and gas production facilities. It says, in 

part, "Tubing systems equal or less than one half inch diameter are exempt 

At least 1 

individual

Helpline
44

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

from the requirements of paragraph (r) of this section and do not need to be 

reported." The regulation does not define the term "tubing systems". Are 

valves, guages, plugs, etc., that are themselves larger than one half inch but 

are associated with piping that is equal or less than one half inch also 

exempt?

43. Provide a definition for 

well testing venting and 

flaring

Currently there is no definition provided for well testing. Please provide 

comment on how well testing is different than well workovers and 

completions.

At least 6 

individuals

Helpline

Does EPA‟s have specific definitions for the following equipment used by 

subpart W sources?

• Natural gas driven pneumatic pump

• Well testing venting and flaring

• Associated gas venting and flaring from produced hydrocarbons 

Specifically for gas venting and flaring how does the GHG reporting rule 

distinguishes between the two?

Currently there is no definition provided for well testing, which makes it 

unclear for reporters to understand the venting emissions they are supposed 

to capture in regards to this emission source. This lack of a definition also 

confuses Section 98.233(m) whereby associated gas venting and flaring 

emissions should be calculated "not in conjunction with well testing." 

There is also no definition of associated gas or further clarification from 

EPA on what types of emission sources should be reported here. Please 

provide explicit clarification on the situations which EPA understands to be 

associated gas venting so that we may appropriately understand how to 

apply the calculation methodology provided.

For Well Testing Venting and Flaring, when should we be conducting these 

measurements? What is the EPA considering the 'testing period'? What type 

of testing does this include?

• What is the difference between associated well venting and flaring and 
45

Appendix A

Summary Of Questions And Issues From The EPA Helpline And Trade Associations Being Resolved By The Proposed Technical 

Corrections And Other Amendments

Technical Issue Question Submitted to EPA

Type and 

approximate 

number of 

submittals

Reference 

(Helpline or 

Trade 

Association 

materials)

well testing venting and flaring? EPA definitions would help.

• EPA definition for “well testing”. Would this be considered the flow back 

period; and
46

APPENDIX B

Summary of Issues From Internal Review Being Addressed by Proposed Amendments

Not all corrections and other amendments correspond directly to questions that were raised by reporters. 

The need for some corrections and other amendments were identified as a result of internal EPA review. 

Below is a summary of the issues that have been raised from the EPA‟s review of Subpart W of Part 98

which are being addressed by the proposed 2011 revisions package.

Overarching Changes

Correcting grammar errors in Subpart W to clarify the meaning and intent of paragraphs.

Correcting Equation W-8, W-9, W-10, W-12, W-13, W-14A, W-21, W-30, and W-39 by 

clarifying the summation operator to make it mathematically functional.

Clarifying, where necessary, that emissions, counts, and other requirements must be reported on 

a sub-basin category basis instead of on a field.

Changes to 98.230

Clarify that EOR operations using natural gas is also included in the industry segment definition 

for onshore petroleum and natural gas production.

Clarify that only source types on a single well-pad or associated with a single well-pad need to 

report under onshore petroleum and natural gas production.

Clarify that the transmission industry segment includes transportation of gas from other 

transmission compressors and to LNG storage facilities.

Clarify the natural gas distribution industry segment definition.

Changes to 98.232

Clarify in paragraph 98.232 (c)(22) that the industry segment is petroleum and natural gas 

production and not onshore production.

Clarify in paragraph 98.233 (c)(22) that facility, with respect to onshore petroleum and natural 

gas production, is as defined in 98.238.

Clarify that CO2, CH4, and N2O emissions must report for each of the sources types listed under 

98.232 (e) through (i).

Clarifying the use of the term above and below grade in 98.232 (i).

Changing custody transfer to transmission-distribution transfer and non-custody transfer to 

metering-regulating station in 98.232 (i).

Addition of equipment leaks from vaults at below grade transmission-distribution transfer 

stations under 98.232 (i).

Removing and reserving the paragraph 98.232 (j).

Clarify that combustion emission for onshore petroleum and natural gas production and natural 

gas distribution must be reported under Subpart W and not Subpart C (General Stationary Fuel 

Combustion Sources). 

Changes to 98.233

Clarify the introductory paragraph to 98.233 (d) by stating that any Calculation Methodology 

under this paragraph can be used as applicable.
47

Clarify the paragraph 98.233 (d)(1) to clarify the CEMS requirements that must be used to 

determine CO2 emissions.

Correcting Equation W-4 in Calculation Methodology 3 and removing the parameter α.

Clarify the parameter definition for 1000 in Equation W-5.

Amend the emission calculation methodology for liquids unloading by clarifying Equation W-7 

so that Ea,n and Th,t is applicable to wells of the same pressure grouping at and same tubing 

diameter. 

Amend the emissions calculation methodology for gas well venting during completions and 

workovers from hydraulic fracturing through: changes to Equation W-10; addition of newly 

assigned Equation W-12; and specifying the number of measurements depending on the number 

of completions and workovers.

Clarify that methane is a possible hydrocarbon going to a flare in 98.233 (n)(2)(iii). 

Amend 98.233 (n) to allow the use of CEMS.

Clarify the parameter definition of MTm in Equation W-24.

Clarify the GHGi factor in Equation W-30 for the industry segments listed under 98.230 (a)(4), 

98.230 (a)(5), 98.230 (a)(6), 98.230 (a)(7), 98.230 (a)(8).

Clarify in paragraph 98.233 (q)(8) that leak detection is only required at above grade stations 

that qualify as transmission-distribution transfer stations.

Clarify the emission factors that must be used for sources in natural gas distribution in 98.233 

(r)(6).

Clarify Equation W-32 by adding the term “meter/regulator run” and the GHGs that need to be 

reported.

Clarifying the requirement set forth in 98.233 (z).

Changes to 98.234

Amending the requirements for optical gas imaging instruments from 98.234 (a)(4) by moving it 

into 98.234 (a)(1).

Adding the applicable references to the Alternative work practice for monitoring equipment 

leaks under 98.234 (a)(1).

Clarify that acoustic stethoscopic devices designed to detect through valve leakage can be used

to determine leaking and non-leaking devices in 98.234 (a)(5).

Changes to 98.236

Clarify that the annual emissions from each industry segment must be reported under 98.236 (a).

Clarify the natural gas distribution industry segment in 98.236(a)(8).

Clarify the reporting requirements for the offshore petroleum and natural gas production 

industry segment.

Clarify that facilities that operate under more than one industry segment are required to report 

emissions under majority use segment.

Clarify that the quantity of recovered gas must be reported separately.

Clarify that emissions from CO2, CH4 and N2O emission must be reported separately throughout 

98.236(c).

Clarify that emissions from high-bleed pneumatic devices, intermittent bleed pneumatic devices, 

low-bleed pneumatic devices must be reported separately on a facility level.
48

Clarify that emission from pneumatic pumps must be combined but that CO2 and CH4 emissions 

must be separated.

Clarify that the reported CO2 concentration can be an annual average for the AGR unit.

Clarify that an annual quantity is required for recovered emissions transferred outside of the 

facility and emissions from an AGR unit.

Additional reporting requirement for AGR units: Unique ID name or ID number for AGR unit; 

and the Calculation Methodology used for determining emission from AGR units.

Clarify that the concentration of CH4 and CO2 in wet natural gas must be reported for glycol 

dehydrators.

Addition of unique ID name or ID number reporting requirement for glycol dehydrator unit.

Clarify that the type of vent gas control must be reported for glycol dehydrators.

Clarify that annual emissions from absorbent dehydrators must be reported.

Addition of the reporting requirement to report the diameter, depth, and pressure of the each 

well selected to represent emission in that tubing size and pressure combination.

Clarify the reference to Equation W-12 in 98.236 (c)(6)(i)(B) and (c)(6)(i)(D).

Clarify that the number blowdowns per unique volume must be reported.

Addition of unique ID name or ID number reporting requirement for blowdown vent.

Addition of unique ID name or ID number reporting requirement for onshore production storage 

tanks.

Clarifying the reference to 98.236 (c)(8)(ii)(B) and (c)(8)(ii)(C) in 98.236 (c)(8)(ii)(D).

Addition of unique ID name or ID number reporting requirement for transmission storage tanks.

Clarify that uncombusted CH4, uncombusted CO2, combusted CO2, and N2O emissions must be 

reported separately for flares.

Addition of unique ID name or ID number reporting requirement for flare stacks.

Report whether emissions from flares were determined using CEMS.

Clarify that a range should be reported for the concentration of CH4 and CO2 for onshore natural 

gas processing.

Addition of 98.233 (a)(8) source category under 98.236 (c)(15)(ii)(A).

Amending 98.233(c)(16) by changing custody transfer gate station to T-D transfer station and 

M&R station to metering-regulating stations.

Addition of unique ID name or ID number reporting requirement for EOR pumps.

Addition of the requirement to report the average API gravity, average gas to oil ratio, and 

average low pressure separator pressure for each sub-basin category.

Changes to 98.237

Addition of the requirement to include an explanation of how company records, engineering 

estimation, or best available information are used to calculate each applicable parameter under 

Subpart W.

Changes to 98.238

Amend the definition of “facility with respect to onshore petroleum and natural gas production 

for purposes of this subpart and subpart A”.

Amend definition of “Farm taps”.

Provide definition of “forced extraction of natural gas liquids”.

Provide definition of “distribution pipeline”.
49

Provide definition of “flare”.

Remove the definition of “field”.

Provide definition of “horizontal well”.

Provide definition of “pressure groupings”.

Provide definition of “sub-basin category”.

Provide definition of “tubing diameter groupings”.

Provide definition of “vertical well”.

Changes to Tables

Clarifying Table W-7 by changing the term “custody transfer city gate station” to “transmissiondistribution gate station”; changing M&R to “metering-regulating” station; and deleting footnote 

1.
50

APPENDIX C

Percent Gas Composition for Natural Gas Transmission Compression, 

Underground Natural Gas Storage, Liquefied Natural Gas (LNG) Storage, LNG 

Import and Export, and Natural Gas Distribution Industry Segments for Methane 

and Carbon Dioxide

EPA set the default mole fraction of methane (CH4) and carbon dioxide (CO2) at 95% and 1%, 

respectively, for the onshore transmission compression, underground natural gas storage industry 

segment, LNG natural gas storage, LNG import and export, and natural gas distribution industry 

segment. Industry petitioned for the default mole fraction because the CH4 and CO2 composition of 

“pipeline quality” gas does not vary significantly for these industry segments. This memorandum 

describes the analysis that was conducted to determine whether the default mole fraction of CO2 and 

CH4 is valid. 

Background

§98.233 (u) Subpart W, using Equation W-35, converts natural gas emission into its respective 

greenhouse gas components. Equation W-35 converts natural gas emission to its respective components 

through the parameter Mi, which is the mole fraction of CO2 and CH4. In the November 2010 Finalized 

Rule, Mi was determined using a known composition of transmission pipeline natural gas. Interstate 

Natural Gas Association of America (INGAA), in their petition, suggested that a default mole fraction 

composition of 95% and 1% for CH4 and CO2, respectively, adequately represents natural gas 

composition in the natural gas transmission and storage segments of subpart W. As a simplification, 

EPA is proposing the use of the default transmission pipeline quality composition for all segments 

downstream of the transmission segment, which would encompass underground storage, liquefied 

natural gas (LNG) storage, LNG import and export, and the natural gas distribution industry segments. 

EPA notes that a portion of the natural gas from production goes straight to Local Distribution 

Companies (LDC)s. Also, some of the LNG imported does not necessarily conform to pipeline 

standards in terms of composition, i.e. the same heat content can be achieved from varying compositions 

of the inherent hydrocarbon components. However, EPA notes that for the purposes of this rule these 

variations are not of consequence, because the majority of the gas conforms to the suggested default 

mole fraction. 

Determination of CO2 and CH4 Composition

Methodology

Pipeline and Gas Journal annually publishes market data on the top 500 transmission companies in the 

United States. Several transmission companies report their gas compositions on their company websites. 

To conduct the analysis, EPA extracted the gas composition data from the largest transmission 

companies that account for 53% of the gas transported through transmission pipelines in the U.S. The 

compositions presented on a specific day were assumed to be representative of the gas composition 

during a whole year of operation for the company. EPA determined the weighted average composition 

of methane using dekatherms as the weighting parameter. 

Results
51

The weighted mole fraction of CH4 and CO2 in the natural gas was 95.8% and 1.12% respectively. The 

maximum CH4 content observed was 96.79% and the minimum was 93.40%. The maximum CO2

content observed was 1.71% and the minimum was 0.64%.

Table 1: CH4 and CO2 mole fraction reported by the largest transmission companies.

2009 Gas 

Throughput 

(Dth/y) 1000

2009 

Transmission 

Miles

CH4 Mole 

Fraction 

Natural Gas

CO2 Mole 

Fraction in 

Natural Gas

El Paso Natural Gas Co. 15,530,679 10,235 - 0.94

Transcontinental Gas Pipe 

Line Corp. 2 3,089,882 9,225 95.69 1.24

Texas Gas Transmission 

LLC 3 2,684,369 5,881 - 1.63

Natural Gas Pipeline Co. of 

America 4 2,481,770 8,939 - 1.24

Tennessee Gas Pipeline 

Co. 5 1,992,417 14,113 96.59 0.71

Gulf South Pipeline Co, LP 61,686,673 6,565 95.98 1.71

CenterPoint Gas 

Transmission 7 1,677,076 6,162 - 1.15

Texas Eastern 

Transmission LP 8 1,658,462 9,314 96.08 1.24

Dominion Transmission 91,407,196 3,452 95.33 0.79

Northern Natural Gas Co. 10 1,181,019 15,028 93.40 0.80

Colorado Interstate Gas Co.

11 1,130,675 4,200 - 1.41

Wyoming Interstate Co. 12 1,056,221 849 - 1.33

Southern Natural Gas Co. 13 1,021,891 7,563 - 1.16

Florida Gas Transmission 

Co. 14 888,535 4,851 95.93 1.09

Northwest Pipeline GP 15 844,609 3,861 95.45 0.64

Great Lakes Gas 

Transmission LP 16 830,429 2,115 96.37 0.76

Gas Transmission 

Northwest Corp. 17 822,930 1,356 96.38 0.72

Kern River Gas 

Transmission Co. 18 804,667 1,680 96.79 0.64

Mole fraction in natural gas 95.8 1.12

1

http://www.elpaso.com/postings/default.asp

2

http://www.1line.williams.com/Transco/index.html

3

https://www.gasquest.txgt.com/Frameset.aspx?url=%2FReports%2FMeasurement%2FGasQuality.aspx%3FNav%3D

True

4

http://www.elpaso.com/postings/default.asp

5

http://www.elpaso.com/postings/default.asp

6

http://customeractivities.gulfsouthpl.com/default.asp?MENU=INFOPOSTINGS

7

http://pipelines.centerpointenergy.com/

8

http://www.link.duke-energy.com/
52

9

http://www.dom.com/about/gas-transmission/index.jsp

10 http://www.northernnaturalgas.com/

11 http://www.elpaso.com/postings/default.asp

12 http://www.elpaso.com/postings/default.asp

13 http://www.elpaso.com/postings/default.asp

14 http://www.hottap.panhandleenergy.com/

15 http://www.northwest.williams.com/NWP_Portal/

16 http://www.glgt.com

17 http://www.gastransmissionnw.com

18 http://services.kernrivergas.com/portal/Desktop.aspx

Conclusions

Using composition data from the top transmission companies, EPA determined that, on average, the 

composition of pipeline quality natural gas is 95.8% methane and 1.12% carbon dioxide. Therefore, a 

default composition of the 95% methane and 1% carbon dioxide would adequately represent the pipeline 

quality natural gas and result in minor errors in reporting. If the reporter believes their gas composition 

is significantly different, as was observed in specific cases, there are provisions that allow reporters to 

use their own composition instead of the default values. 
53

APPENDIX D

Proposed Pressure Groupings for Monitoring Emissions from the Well Venting for 

Liquids Unloading Emissions Source by Sub-Basin.

Subpart W of the greenhouse gas reporting rule requires onshore petroleum and natural gas production 

facilities to report emissions from well venting for liquids unloading measurements as defined in 40 

CFR 98.232 thru 98.238. In this action, EPA is proposing to replace the EIA field designation, referred 

to as the EIA Oil and Gas Field Code Master List or “FCML” in this document, with the “sub-basin” 

designation for sampling. EPA anticipates that the same quality of emissions data resulting from the 

“field” designation would be maintained with the “sub-basin” designation. With the sub-basin 

designation, EPA is proposing to include a further designation for which the reporter would take 

measurements within a sub-basin based on a combination of wellhead pressure group and unique tubing 

grouping as applicable. This appendix describes how EPA developed the wellhead pressure groupings.

Background

The Subpart W final rule requires a measurement to be taken from one well per liquids unloading event 

for each unique tubing diameter and producing horizon/formation combination in an estimated 18,500 

gas producing fields. The emissions measurement from this sample is to be then applied to all unloading 

events of a similar tubing diameter, producing horizon/formation combination in each field using the 

FCML as applicable. 

EPA received several requests to reconsider the provision in the final rule which requires reporters to 

take field-level measurements using the FCML. Commenters argued against using the FCML and 

asserted that the FCML did not address new fields and that the list changed significantly from year-toyear , and as a result reporters should not be required to us the FCML for measurement and sampling 

under the provisions in the final rule. EPA does not agree that the FCML is not an appropriate tool to 

use for sampling and measurement under subpart W, however, EPA has proposed an alternative subbasin concept that will result in the same quality of emissions being reported. In EPAs discussions with 

these commenters, the commenters agreed conceptually that pressure was a factor in liquids unloading 

of the volume of gas vented, and that a sub-basin geographic delineation using counties to replace the 

EIA field code master list was acceptable.

EPA is proposing a county boundary delineation in place of the FCML delineation for determining a 

surface well classification in a sub-basin grouping. However, there are only 800 counties in the U.S. 

with gas producing wells, and each county may encompass many producing horizon/formation 

combinations with quite different production characteristics. Therefore to apply a single sample of one 

well liquid unloading event to all other similar events in a sub-basin (county), it is necessary to group 

those events by factors that most affect gas venting volume: namely gas well pressure and tubing 

diameter. EPA chose five pressure ranges, four bounded between zero and 200 psig at the wellhead and 

one unbounded range above 200 psig. Further, to be more definitive on “unique tubing diameter,” EPA 

selected three nominal ranges of typical gas well tubing diameters. Therefore, for gas well liquids 

unloading, the operator is required to measure the natural gas flow rate of one liquids unloading event 

for each sub-basin, pressure range, and unique tubing diameter, instead of the provisions in the final rule 
54

which required measuring the natural gas flow rate of a liquids unloading event for each well tubing 

diameter and producing horizon/formation combination in each gas producing field. 

This memo describes the analysis that was performed to optimize the pressure groups to a minimum 

potential error with one sample well applied to all other wells in each pressure group.

The bias or error in emissions reporting for the well liquids unloading source can be minimized by using 

a set of different pressure groups such that the sum of errors resulting from each pressure grouping is the 

lowest for the national emissions from this source. These pressure groups would enable reporters to 

estimate their emissions for all wells in a given group based on a one well sample in the pressure group. 

Method

This analysis is based on five pressure groups to be consistent with, but lower burden than, the 2010 

final rule. The reporter will still be able to measure the one liquid unloading event in each countypressure range-tubing diameter range combination to apply to all other well unloading events in that 

same sub-basin category. The reporter will also still be able to estimate the emissions from every liquid 

unloading event using the equations in the rule that are a function of each well‟s geometry, shut-in 

pressure and number/duration of venting events per year. EPA has determined that the calculation of 

each well unloading will be less costly than the field measurement of one event in each sub-basin 

category, and therefore, this amendment adds no additional burden. 

While the calculation of liquids unloading vent emissions in the rule, 40 CFR 98.233(f)(2), is based on 

reservoir shut-in pressure, this data is not reliably available in public literature, so just for this method of 

optimizing pressure ranges, the well flowing pressure data is used as a surrogate for shut-in pressure. 

The five pressure groups consist of four bounded groups between 0 and 200 psig, and one unbounded 

group above 200 psig. The analysis is designed to minimize the total error from the entire national 

population of conventional wells subject to liquids loading, assuming all wells are estimated by using 

the values from a representative gas well in each pressure group.

The first step was to estimate the emissions from a representative gas well. The estimate assumed an 

average gas well with a six inch casing and a depth of 6,000 feet. The estimate applied the Subpart W 

calculation methodology wherein the gas volume in the well casing at the average and 

maximum/minimum flowing pressure listed in the HPDI® database in the group would be blown to the 

atmosphere. The following equation was used to determine the volume of gas released from the well 

casing.

L

d

P

P

V

atm

Well

Vent 4

2

Where:

VVent = Volume of vented gas, scf 

PWell = Pressure surrogate (i.e. flowing pressure) inside well casing, psia

Patm = Atmospheric pressure, 14.7 psia

d = Diameter of well casing, taken to be 6 inches (0.5 ft)

L = Length of well casing, taken to be 6,000 ft

The next step involved scaling the emissions to all wells. This was done using data from the HPDI® 

database. All conventional gas wells were grouped by wellhead flowing pressure specified in HPDI® as 

a surrogate for shut-in pressure, in 5 psi increments. Any wells that had 0 psig shut-in pressure or wells 
55

without listed pressures were excluded from the optimization calculation. All wells with greater than 

200 psig were grouped in the unbounded pressure group, and not included in the optimization 

calculation, because they were assumed to have adequate flowing pressure so as to not require liquids 

unloading to the atmosphere. Marginal wells, i.e. gas wells in highly depleted, low pressure reservoirs, 

were also taken into consideration. The Department of Energy classified wells that produce less than 

60,000 scfd as a marginal wells. Based on that classification of marginal wells, it was determined that 

only 2% of marginal wells would be required to report under Subpart W. Therefore, for simplicity in 

this optimization of pressure ranges, all of the marginal wells in the HPDI® data were placed in the 

lowest pressure group for the analysis.

Total error was defined as total emissions at the maximum for each pressure group minus the total 

emissions at the average pressure for each group. This is shown in the following equation.

100%

max

avg

avg

EM

EM EM

Error

Where:

Error = Total industry error, % 

ΣEMmax = Sum of emissions at the maximum of each pressure group, scf

ΣEMavg = Sum of emissions at the average of each pressure group, scf

The total error was minimized by allowing the Microsoft Excel Solver function to allocate a portion of 

wells to each pressure group, until the optimum allocation was reached. 

Results

From the analysis, five optimal pressure groups were chosen. The five groups were, in psig, 0-25, 25-

60, 60-110, 110-200, 200+. From these pressure groups, excluding 200+ psig wells on the basis that all 

wells above that pressure would not require liquids unloading to the atmosphere, the total error was 

determined to be 29.82%. The results are summarized in the table below.

Table 1: Summary of Pressure Group Analysis

Pressure Groups (psig) Number of 

Wells

Emissions (MMscf)

Low High Average Average High

1 0 25 13 24,254 52.9 77.2

2 25 60 43 22,851 104.8 136.8

3 60 110 85 14,692 117.4 146.8

4 110 200 155 8,398 114.2 144.5

Totals: 70,195 389.2 505.3

Error: 29.82%

Summary

For the number of wells potentially requiring liquids unloading in each of the four pressure ranges 

specified above, the deviation in emissions at the lower and upper bound relative to the average pressure 

in the range, for all ranges, is ±30%. It is assumed that the large majority of wells with flowing pressure 
56

above 200 psig will have sufficient reservoir energy to either not require liquids unloading at all, or are 

suitable for operation of a closed plunger lift system that does not vent gas to the atmosphere. As this 

number of measurement data points for county sub-basins, five pressure ranges and three tubing 

diameter ranges, is likely fewer than the final Subpart W rule, should reporters choose measurement 

over calculation, the burden would still be lower. However, given that the calculation methodology can 

be performed for all wells with readily available data on each well, and without any field data other than 

number and duration of well venting for liquids unloading, EPA still believes that that method is lower 

cost and so this amendment of the rule adds no additional cost burden. For further information please 

see the “Sub-basin Entity Pressure Range Analysis” document and the Sub-basin Entity By US County

document in the docket: EPA-HQ-OAR-2011-0512. 
57

APPENDIX E

Impact on Emissions Coverage Resulting from Proposed Amendments

EPA has proposed several amendments to provisions outlined in 40 CFR part 98 Subpart W. A subset 

of those amendments to provisions may have an impact on the emissions coverage under subpart W. 

Those amendments are as follows: 1) providing an equipment threshold for internal combustion 

equipment in onshore production; 2) providing a threshold for leak detection at transmission-distribution 

transfer stations; and 3) clarifying separate reporting of vented versus flared emissions. This appendix 

describes the potential impact of the proposed amendments on the emissions coverage for subpart W.

Equipment Threshold for Internal Combustion Engines 

For both the onshore petroleum and natural gas industry segment and the natural gas distribution 

industry segment, external fuel combustion emissions from portable or stationary equipment with a rated 

heat capacity less than or equal to 5 MMBtu/hr only activity data are required to be reported. This 5 

MMBtu threshold was developed based on significant data provided in comments to the 2010 subpart W 

proposal (75 FR 18608). Based on the information submitted (Please see Docket EPA-HQ-2009-0923 

Equipment Threshold for Small Combustion Units for further background on data submitted), it was 

estimated that anywhere from 10s to 100s of thousands of small, external combustion devices such as 

line heaters, separator heaters, tank heaters, freeze protection heaters, which do not have fuel gas meters 

and, by nature of their automatic temperature controls, do not have records of on/off operating factors 

are below the 5 MMBtu threshold for rated heat capacity. EPA concluded that it was sufficient to 

require only the reporting of activity data for external combustion equipment below the threshold. 

Shortly after finalizing subpart W and publication in the Federal Register (75 FR 74458), EPA received 

petitions for reconsideration on various provisions in the final rule, including the provision requiring 

reporting of greenhouse gas emissions from internal combustion engines. In specific, industry requested 

reconsideration of a threshold for very small internal combustion sources, such as temporary, portable 

electrical generators, air compressors, welding machines and lighting generators used briefly at 

wellheads for construction and maintenance. From data available in onshore production permitting, 

EPA determined that a 5 MMBtu/hr threshold for internal combustion equivalent to the 5MMBtu/hr 

threshold for external combustion devices would exempt virtually all wellhead compressor and pump 

engines from onshore production reporting. EPA researched the available sizes of portable electric 

generators used for wellhead maintenance or small construction work (i.e. not well drilling and 

workover rigs or hydraulic fracture pumps) and found that virtually all are well under 1 MMBtu/hr. 

This source, portable generators for wellhead maintenance or small construction, was not included in the 

threshold analysis to the final rule because EPA had no activity data on this source, so exempting it from 

reporting does not significantly affect the coverage of Subpart W and avoids a burden of gathering 

considerable data from contractors. Further, EPA evaluated wellhead compressors that use natural gas, 

as these sources are also below 5 MMBtu, however, EPA did not propose an equipment threshold for 

wellhead compressors that use natural gas, because that is the bulk of combustion emissions from 

onshore production and there are no reliable estimates for this number The estimate of natural gas 

consumption provided by EIA is not of sufficient quality and EPA seeks this information to sufficiently 

understand natural gas consumption at production operations. Hence, the Agency currently lacks 

sufficient data on this source of emissions and believes that source may be a major contributor to the 

emissions from the onshore production industry segment. Subpart W is requiring reporting of activity 
58

data for external combustion devices below the 5 MMBtu/hr threshold, because these are typically 

stationary or long term positioned portable units. However, the 1 MMBtu/hr exemption does not require 

reporting activity data, because these units are virtually all portable and onsite for brief periods. 

Conclusion

EPA concludes that adding this internal combustion threshold will change coverage only marginally, 

because maintenance related equipment are not expected to have significant emissions. But this change 

will reduce cost burden of collecting and reporting contractor emissions from relatively small, portable 

engines used briefly on well pads for maintenance and small construction.

Threshold for Exempting Leak Detection at Transmission-Distribution Transfer Stations

Subpart W of the Greenhouse Gas Reporting Rule requires reporting of emissions from natural gas 

distribution facilities, including the reporting of emissions detected using leak detection methods and 

emissions estimated using population emission factors. For the natural gas distribution industry 

segment, facilities were required to perform leak detection at transmission-distribution transfer facilities 

where gas is transferred from a transmission pipeline into a distribution pipeline.

In this proposal, EPA proposed several revisions to terms used in the final rule to further clarify EPA‟s 

intent of who would be covered under the rule. The term “custody transfer” has been replaced with 

“transmission-distribution transfer station.” In addition, EPA has proposed to universally use the term 

“metering-regulating station” throughout the rule, and to clarify that TD transfer stations are a subset of 

those metering-regulating stations. 

The proposed rule requires leak detection at both above and below grade metering-regulating stations,

where gas moves from a transmission pipeline into a distribution pipeline. EPA understands that these 

TD transfer stations come in many sizes and configurations, including some very small stations with, 

perhaps, a single meter run, with and without pressure regulation. EPA also understands that there are 

many above grade meter-regulator stations that are not at gas transfer points between transmission and 

distribution, and are not customer meters, sometimes referred to as district regulators. For these stations, 

Subpart W requires the application of a population leak factor developed uniquely by each company 

from the leak surveys performed on the TD transfer stations. Therefore, all above grade meteringregulating stations are accounted for in the final rule. In consideration of industry‟s comment that 

performing leak surveys on some very small, remote, aboveground metering-regulating stations that 

transfer gas from transmission pipelines to distribution pipelines are burdensome and unwarranted by 

the improvement in emissions estimation, EPA is considering an appropriate threshold for such small, 

remote stations. Such a threshold would not exclude these TD transfer stations below any threshold 

from reporting emissions, but rather put them in the same class as the metering-regulating stations (i.e. 

applying the population leak factor developed from the company‟s leak surveys). Therefore, providing a 

threshold would not change the coverage. However, this could lower the quality of data being reported 

because a small TD station does always equate to a low magnitude of emissions. Emissions from a TD 

station are dependent mainly on factors such as maintenance practices and pressure drop across the 

regulator. 

In conclusion, EPA does not anticipate that the emissions coverage will be greatly impacted by 

providing a threshold for leak detection at TD transfer stations; however, the quality of the emissions 
59

may be less because the emission factor may not accurately portray the emissions from a particular 

station..

Separate reporting of vented versus flared emissions

EPA has clarified in this proposal that vented emissions from each source should be reported separately 

from flared emissions. Although this has always been EPA‟s intent, the data reporting section did not 

clearly state this requirement for all sources; while some sources in the final rule clearly state this 

requirement. This clarification to the data reporting requirement is not expected to change emissions 

coverage because the monitoring methods are not impacted by the change. Furthermore, this will 

improve the data quality being received as vented emissions will clearly be reported separately from 

flared emissions.