Appendix A:  

List of Materials SBAR Panel shared with Small Entity Representatives  

Small Business Advocacy Review Panel on EPA’s Planned Proposed Rule

Emission Standards for New and Modified Sources in the Oil and Natural Gas Sector
Small Business Advocacy Review Panel

Pre-Panel Outreach Meeting with Small Entity Representatives

Emission Standards for New and Modified Sources in the Oil and Natural 

Gas Sector

Tuesday, May 19, 2015 

EPA HQ, WJC North, room 6530 

1:00 pm – 3:00 pm (eastern) 

1:00 Welcome (EPA’s Small Business Advocacy Chair, Office of Policy (OP)) 

1:05 Introduction of Panel Members/Staff 

o EPA/Office of Air (OAR) 

o SBA/Office of Advocacy 

o OMB/Office of Information and Regulatory Affairs (OIRA) 

1:10 Introduction of SERs and Other Attendees (OP) 

1:15 Panel Process Questions? (OP takes questions from SERs) 

1:20 Follow-up Questions about Rule Presentation (OAR takes questions from SERs) 

1:50 Discussion of the Rulemaking (SERs with Panel) 

2:50 Summary and Closing (EPA/OP) 

********************************************** 

Teleconference dial-in number: (866) 299-3188 

Conference code: 202 564 1550

Dial the toll-free teleconference number listed above. At the prompt, enter the conference code 

followed by the pound [#] sign. Note: You will hear music until the leader dials into the call.
Office of the Administrator

Office of Policy

Office of Regulatory Policy and Management

http://www.epa.gov/op/orpm.html

An Overview of the Small Business 

Advocacy Review Panel Process

Pre-Panel Outreach Meeting with Potential SERs

May 19, 2014
This presentation covers...

• What is a Small Business Advocacy Review (SBAR) 

Panel?

• How does a Panel fit into the rulemaking process?

• How do Small Entity Representatives (SERs) participate 

in the Panel process?

• What does the Panel do with SER recommendations?

• What is the difference between this Pre-Panel meeting 

and the future Panel meeting?

2
What is an SBAR Panel?

• Chaired by EPA’s Small Business Advocacy 

Chair (EPA’s SBAC from Office of Policy)

• Other Panel members consist wholly of 

federal employees: 

 Program Office manager;

 Office of Management and Budget (Office of 

Information and Regulatory Affairs (OIRA) 

Administrator); and

 Small Business Administration, Chief Counsel for 

Advocacy.

3
What is an SBAR Panel? (cont’d.)

• SBREFA1 amended the 1980 Regulatory 

Flexibility Act (RFA), which requires 

agencies to:

“assure that small entities have been given an 

opportunity to participate in the rulemaking” process for 

any rule “which will have a significant economic impact 

on a substantial number of small entities.”2

1 Small Business Regulatory Enforcement Fairness Act of 1996

2 5 USC 609(a)

4
What is an SBAR Panel? (cont’d.)

“the panel shall review any material the agency has prepared..., including 

any draft proposed rule, [and] collect advice and recommendations of 

each individual small entity representative ..., on issues related to”1 the 

following:

 Who are the small entities to which the proposed rule will apply? 2

 What are the anticipated compliance requirements of the upcoming 

proposed rule? 3

 Are there any existing federal rules that may overlap or conflict with the 

regulation? 4

 Are there any significant regulatory alternatives that could 

minimize the impact on small entities? 5

5

1 5 USC 609(b)(4)

2 5 USC 603(b)(3)

3 5 USC 603(b)(4)

4 5 USC 603(b)(5)

5 5 USC 603(c)
Where does the Panel fit within the 

rulemaking process?

“any material the agency has prepared” 

 The RFA requires that a Panel, if one is necessary, be conducted 

prior to publication of a proposed rule.

 It is EPA’s policy to host Panels well before a proposed rule is 

written so we have adequate time to incorporate SER advice and 

recommendations into senior management decision-making 

about the proposed rule.

 EPA generally does not have draft proposed rule text available at 

the time a Panel is convened, though we expect to discuss 

regulatory alternatives in as great a detail as we can.

 Participation in the outreach meetings does not preclude, or take 

the place of, participation in the normal public comment period 

at the time the rule is proposed.

6
How do SERs participate?

“collect advice and recommendations”

• You have the opportunity, because of your status as a 

small entity who is expected to be regulated by this rule, 

to influence the decisions senior EPA officials make 

about the forthcoming regulation

• Advice and recommendations collected via two Outreach 

meetings with SERs:

 EPA holds a pre-panel outreach meeting with potential SERs 

(this one), and 

 after the Panel convenes, the Panel itself will hold an outreach 

meeting with SERs.

7
How do SERs participate? (cont’d.)

 You will have an opportunity to submit written 

comments as well as the verbal comments 

you provide in the outreach meetings.

 Reminder: Those of you joining this meeting 

to assist a potential SER (aka “helpers”) are 

asked to limit your input, both verbal and 

written) to representation of the small entity 

you are assisting.

8
What does the Panel do 

with your recommendations?

• EPA, OMB, and SBA prepare a joint Panel 

report:

 Submitted to the EPA Administrator

 Considered during senior-management decisionmaking prior to the issuance of the proposed rule

 Placed in the rule’s docket when the proposed rule is 

published

9
Pre-Panel vs. Panel Outreach Mtg.?

• Pre-Panel Outreach Meeting

 Conducted by EPA with SBA and OMB as invitees

 Overview of the RFA, how the Panel process works, 

and the role of SERs

 Background and overview of proposed rulemaking 

• Panel Outreach Meeting

 Chaired by SBAC, but all Panel members have active 

role

 Bulk of meeting spent discussing regulatory 

alternatives and input of SERs

10
Thank You

• We realize that small entities make 

significant sacrifices to participate

• Thank you for taking time and effort away 

from your business or organization to 

assist the Panel in this important work

11
Contact Information

Nicole Owens

Director, Regulatory Management

EPA Office of Policy

202-564-1550

owens.nicole@epa.gov

12
Pre-Panel Outreach Briefing: 

Emission Standards for New and 

Modified Sources in the Oil and 

Natural Gas Sector

May 2015
Deliberative - Do Not Cite or Quote 

Overview

► Oil and Gas Sector Description

► What are New Source Performance Standard (NSPS)?

► Methane Strategy

► White House Announcement

► Hydraulically Fracture Oil Well Completions

► Fugitive Emissions at Well Sites, Gathering and Boosting Stations and 

Compressor Stations

► Pneumatic Pumps

► Pneumatic Controllers

► Compressors

► Liquids Unloading

► Potential Impacts of the Rule

► Schedule

2
Deliberative - Do Not Cite or Quote 

Oil and Gas Sector Description

3

Leaks from unprotected steel mains and service lines

Picture courtesy of 

American Gas 

Association

Well completions

Oil Production

Storage tanks

Compressors

Glycol dehydrators

Pneumatic controllers

Well completions

Natural Gas Production & Processing

Venting of gas for maintenance or repair 

of pipelines or compressors

Leaks from compressor stations 

Gas Transmission

Leaks at metering and regulating stations

Gas Distribution

Pipeline blowdowns

Processing plant leaks 

Covered in Oil and Gas 

White Papers

Liquids Unloading

Storage tanks

Leaks 

Produced Water Evaporation Ponds

Gas plant sweetening units 

Compressors

Storage tanks

Glycol dehydrators

Pneumatic Controllers

Pneumatic Controllers

Leaks 

Pneumatic controllers

Pneumatic pumps

Pneumatic pumps
Deliberative - Do Not Cite or Quote 

What are New Source Performance Standard (NSPS)?

► NSPS are technology based standards that apply to stationary sources that 

“cause, or contribute significantly to air pollution which may reasonably be 

anticipated to endanger public health or welfare”

► Costs are considered in the development of NSPS

► The Clean Air Act (CAA) requires EPA review, and if appropriate, revise a NSPS 

at least every 8 years

► April 2012 Oil and Gas NSPS

► Regulated VOC emissions from: 

• Well completions (completed reconsideration 12/31/14 to make time-critical changes)

• Pneumatic controllers

• Compressors

• Equipment leaks at gas processing plants (strengthened)

• Storage vessels (completed reconsideration 8/2/13 to make time-critical changes)

► Significant methane co-benefits from reductions in VOC emissions:

• By 2015, expected to achieve reductions of about 19 to 33 million metric ton of CO2e
Deliberative - Do Not Cite or Quote 

Methane Strategy

► Strategy to Reduce Methane Emissions released March 2014

► Component of Obama Administration’s Climate Action Plan

► Identified oil and gas sector as a key source of methane emissions (28% 

of emissions in 2012, second largest category)

► Outlined schedule for potential future regulation of oil and gas 

► Release five white papers: April 2014

► Make peer review comments available:

• Peer review complete June 2014

• Comments currently available on white paper website

► Determine if further regulation is necessary: January 2015

► Complete rulemakings and state requirements if applicable: End 2016

5
Deliberative - Do Not Cite or Quote 

White House Announcement

► On January 14, 2015 the White House announced its path 

forward on oil and gas; for the EPA the path forward included:

► NSPS

► Control Techniques Guidelines (CTG) Document

► Expanded Natural Gas STAR Program

► Consider enhancing Greenhouse Gas Reporting Program

► Specific NSPS commitments

► Reduce emissions of GHGs and VOCs

► Add equipment and processes to those source types currently 

covered by NSPS standards

• Specifically look at sources from the Oil and Gas White Papers

► Schedule

• Proposal: Summer 2015

• Final: Spring 2016

6
Deliberative - Do Not Cite or Quote 

Hydraulically Fractured Oil Well Completions

► Emissions occur as wells “flowback” during the completion process

► Available studies estimate emissions (see Oil Wells white paper pg 44):

► Methane: 44,000 tons per year to 247,000 tons per year

► VOC: 37,000 tons per year to 116,000 tons per year

► Reduced emission completions (“green completions”) (see Oil Wells white paper pg 23):

► Gas is captured when feasible and flared when infeasible

► Results in gas capture for wells that have access to pipeline infrastructure

► Reduces emissions by 95% or about 7 tons methane and 6 tons VOC per completion

► Currently a common practice in the field

► Approximate cost: $20,000 per completion (depends on duration)

• Cost estimate based on contracting with specialized service providers

► Completion combustion (“flaring”) (see Oil Wells white paper pg 27)

► Pipeline infrastructures is unnecessary

► Reduces emissions by 95% or about 7 tons methane and 6 tons VOC per completion

► Does not result in gas capture

► Secondary impacts from flaring: NOx, CO, and PM

► Approximate cost: $4,000 per completion

• Cost estimate based on conservative assumption of purchasing a combustion device for each completion

► Some states require green completions in combination with flaring

► WY, CO

7
Deliberative - Do Not Cite or Quote 

Fugitive Emissions at Well Sites, Gathering and 

Boosting Stations and Compressor Stations

► Multiple sources of fugitive emissions at well sites, gathering and boosting stations, and 

compressor stations

► Valves, connectors, open-ended lines, pressure relief valves, thief hatches on tanks, etc

► Available studies estimate emissions (see Leaks white paper pg 17):

► Methane: 333,000 MT from gas production, 34,000 MT from gas processing, and 114,000 MT from gas 

transmission

► Leaks at facility may range from about 5 to 160 tons per year methane or 1 to 10 tons per year VOC depending 

on where in the supply chain the emissions occur

► Reductions at facility may range from about 3 to 100 tons per year methane or 1 to 6 tons per year VOC 

► Several technologies are available to find and fix these sources

► Infrared cameras

► Portable analyzers

► Acoustic leak detectors

► Ambient/mobile monitoring

► Estimated costs depend on several factors (see Leaks white paper pg 36):

► Detection technologies 

► Frequency of detection surveys

► Size and type of site (e.g., well site, gathering and boosting station, compressor station)

► $1,500 to $20,000 per facility per year depending on type of facility

► Cost estimate based upon sum of expected company-level activities (planning, reporting, and recordkeeping, 

for example) and site-level costs based on contracting with specialized service providers

► Several states require monitoring and repair of these emission sources

► WY, CO, OH, PA, UT 8
Deliberative - Do Not Cite or Quote 

Pneumatic Pumps

► Emissions are vented when pneumatic pumps operate

► Multiple types of pneumatic pumps

► Chemical/methanol injection pumps

• Small and very common at well sites

► Diaphragm pumps

• Similar to chemical/methanol injection pumps but larger

► Gas assist pumps (glycol pumps)

• Used on glycol dehydrators to circulate the glycol

• Emissions come from the same vent as the rest of the glycol dehydrator emissions

• Currently regulated as part of the National Emission Standards for Hazardous Air Pollutants (NESHAP)

► Available studies estimate emissions (see Pneumatic Devices white paper pg 32):

► 115,000 MT methane from chemical/methanol and diaphragm pumps

► 393,000 MT methane from gas assist pumps

► Control options 

► Reductions range from 95% to 100% depending on control option, or about 0.5 to 4 tons methane per year and 0.1 to 1.0 

tons VOC per year on a facility basis

► Combust emissions (e.g., flare )

► Capture through a vapor recovery unit

► Install non-emitting pumps (e.g., solar, instrument air or electric)

► Estimated costs

► Cost to combust or capture is low if controls are already on site: about $2000 for purchase and installation of piping

► Cost of solar pumps similar to installing a new pneumatic pump but they may not be technically feasible in all situations

► WY regulates emissions from pneumatic pumps

9
Deliberative - Do Not Cite or Quote 

Pneumatic Controllers

► Continuous bleed gas driven pneumatic controllers “bleed” as part of normal 

operation

► Available studies estimate emissions (see Pneumatic Devices white paper pg 13):

► Methane: 770,000 MT from oil and gas production, 2,000 MT from gas processing, 

and 250,000 MT from gas transmission and storage

► 2012 NSPS regulated continuous bleed pneumatic controllers in 

production/processing but not transmission/storage

► Production: Set an emission limit of 6 scf/hr (i.e., “low bleed”)

► Processing: Set an emission limit of 0 scf/hr (i.e., instrument air or electric controllers)

► Control options (see Pneumatic Devices white paper pg 36):

► Install “low” bleed controllers

• Reduces emissions by >90% in most cases, or about 6 tons methane per year or 0.2 tons per 

year VOC

► Install non-emitting controllers (e.g., solar, instrument air or electric)

• Requires reliable access to electricity

• Reduces emissions by 100%, or about 6 tons methane per year or 0.2 tons per year VOC

► Estimated costs (see Pneumatic Devices white paper pg 36):

► $30 to install a low bleed controller instead of a high bleed, based on annualized cost of controller 

with capital costs of around $230

► Many states regulate emissions from pneumatic controllers

10
Deliberative - Do Not Cite or Quote 

Compressors

► Wet seal centrifugal compressors vent emissions when degassing compressor seals

► Reciprocating compressors vent emissions from the rod packing

► Available studies estimate emissions (see Compressors white paper pg 18):

► Methane: 86,000 MT from gas production, 724,000 MT from gas processing, and 1,261,000 MT from gas 

transmission and storage

► 2012 NSPS regulated compressors in production/processing but not transmission/storage; argued low total VOC 

emissions

► Wet seal centrifugal compressors: 95% control for new and modified wet seal compressors

► Reciprocating compressors: Rod packing replacement every 26,000 hours or route emissions to a process

► Control options (see Compressors white paper pg 29):

► Controls reduce about 20 to 140 tons methane per year and 1 to 4 tons VOC per year depending on type of 

compressor and control

► Combust emissions (e.g., flare )

• $100,000 annualized cost per compressor

► Capture through a vapor recovery unit (VRU)

• $20,000 annualized cost (without considering gas savings) per VRU; net savings when recovered gas is considered

► Install dry seals instead of wet seals

• Net savings when gas savings and reduced O&M costs are considered

► Replace reciprocating compressor rod packing

• $2,000 to $7,000 per compressor each time the rod packing is replaced

► Many states regulate emissions from compressors 11
Deliberative - Do Not Cite or Quote 

Liquids Unloading

► In mature gas wells, the accumulation of liquids in the well can impede and sometimes 

halt gas production 

► Certain techniques for removing this liquid result in venting the well to atmosphere

► These techniques vary depending on well characteristics

► Available studies estimate emissions:

► Methane: 270,000 MT to 320,000 MT (see Liquids Unloading white paper pg 8)

► 2012 NSPS did not regulate this source

► Phase 2 of the UT Methane Study was released in December 2014 and directly 

measured emissions

► Control options (see Liquids Unloading white paper pg 14)

► Plunger lift systems with and without smart automation

• $2,000 (without smart automation) to $20,000 (with smart automation)

► Artificial lifts (e.g., pump jacks)

• $41,000 to $62,000

► Velocity tubing

• $7,000 to $64,000

► Foaming agents

• $500 to $9,880

► CO regulates emissions from liquids unloading

12
Deliberative - Do Not Cite or Quote 

Potential Impacts of the Rule

► Evaluating appropriateness of setting GHG and/or VOC standards for 

each of the white paper sources

► Ways EPA can ease impact to industry

► Avoid regulating good behavior

• Low bleed controllers or zero-bleed pneumatic controllers

• Dry seal compressors

• Zero emission pneumatic pumps

• Sites with low fugitive emissions

► Incentive technologies that capture rather than flare gas, resulting in 

economic benefit for the owner/operator

• RECs

• Dry seal compressors

• Low bleed pneumatic controllers

• Zero emission pumps

• Finding and fixing leaks

13
Deliberative - Do Not Cite or Quote 

SER Input Requested

► Is there any information that would improve our understanding of the 

number of small entities that could be affected by this action?

► What recommendations do you have for reducing recordkeeping and 

reporting burden on small businesses?

► Are there other federal rules that apply to small businesses that may 

overlap with this action?

► What recommendations do you have to reduce the burden to small 

businesses while reducing emissions from the white paper sources?

► Oil well completions

► Fugitive emissions

► Pneumatic pumps

► Pneumatic controllers

► Compressors

► Liquids unloading

14
Deliberative - Do Not Cite or Quote 

Schedule

Milestones Dates

Convene SBAR Panel Spring 2015

Complete SBAR Panel Summer 2015

Proposal Signature Summer 2015

Final Signature Spring 2016
Potential Small Entity Representatives - Emission Standards for New and Modified Sources in the 

Oil and Natural Gas Sector1

Name Affiliation Contact Information

Tom Murphy2

Manager, Environmental 

Compliance

Unitil Service Corp

New Hampshire

murphyt@unitil.com

603-379-3829

Michalene Reilly

Executive Director

Hoosier Energy REC, Inc

Indiana

mreilly@hepn.com

812-935-4711

David Stewart

Corporate Director, EHS & 

Regulatory Compliance

Bonanza Creek Energy, Inc

Colorado

dstewart@bonanzacrk.com

720-225-6696

Julie Lang

Director of Regulatory Affairs

Prism Midstream LLC

Texas

jlang@prism-midstream.com

817-803-5265

Chuck Cornell

Senior Regulatory Lead

Jonah Energy LLC

Colorado

chuck.cornell@jonahenergy.com

720-577-1251

Rudy F. Vogt, III

Geologist/Partner AND

Current President of the KY 

Oil & Gas Association

Cumberland Valley 

Resources LLC

Kentucky

rvogt@cvresources.com

502-479-9056

Doug Mehan

Director of Health, 

Environmental & Safety

PennEnergy Resources LLC

Pennsylvania

dgmehan@pennenergyresources.com

412-275-3209

Robert Mitchell

Vice President

Carrera Gas Companies LLC

Oklahoma

rmitchell@carreragas.com

918-710-4128

Arthur Stewart

President

Cameron Energy Company

Pennsylvania

camelot1@atlanticbb.net

814-968-3337

 

 Gas Processors Association, represented by Matt Hite and Mark Sutton; and Independent Petroleum 

Association of America, represented by Matt Kellogg will serve as Helpers.

2 Pam Lacey from American Gas Association will serve as Tom’s helper
Name Affiliation Contact Information

Jerry James

President

Artex Oil Company

Ohio

jjames@artexoil.com

740-373-3313

Kim Angove

Executive Assistant

Pennsylvania Grade Crude 

Oil Coalition (PGCC)

admin@pagcoc.org

814-230-3033

Shane Kriebel3

Production Business 

Manager, Kriebel Companies

Pennsylvania Independent 

Oil & Gas Association 

(PIOGA)

SCKriebel@kriebelgas.com

814-226-4160

Kathleen M. Sgamma

Vice President of 

Government & Public Affairs

Western Energy Alliance

Colorado

ksgamma@westernenergyalliance.org

303-501-1059

Mari Ruckel

Vice President, Government 

and Regulatory Affairs 

Texas Oil and Gas 

Association

mruckel@toga.org

512-478-6631

Sarah Bartlett

Lead Air Quality EHS 

Professional

PDC Energy, Inc.

Colorado

Sarah.Bartlett@PDCE.com

303-831-3969

 

3Dave Ochs and Roy Rakiewicz will serve as Helpers. 
Oil and Natural Gas White Papers 

Abridged Summary 

Prepared for the Small Business Advocacy Review Panel 

US EPA Office of Air Quality Standards 

May 18, 2015 
2 

1.0 Introduction 

1.1 Purpose of this Document 

On April 15, 2014, the EPA released for external peer review five technical white papers on 

potentially significant sources of emissions in the oil and gas sector. The white papers presented the

Agency’s understanding of emissions and available emissions mitigation techniques from potentially 

significant sources of emissions in the oil and natural gas sector. Specifically, the white papers focus on 

technical issues covering emissions and mitigation techniques that target methane and volatile organic

compounds (VOCs) for following emission sources: 

• Oil well completions and ongoing production 

• Leaks 

• Compressors 

• Pneumatic devices 

• Liquids unloading 

The EPA conducted an independent peer review of the white papers as well as welcomed submittal 

of technical information and data from the public. 

This document provides an abridged summary of the content of the white papers and a high level 

overview of the comments submitted by the peer reviewers. 

Both the white papers and peer reviewer comment are available for review at 

http://www.epa.gov/airquality/oilandgas/whitepapers.html. 

1.2 Peer Reviewers 

Table 1 provides a list of the peer review panel that provided comment to the EPA on the 

individual whitepapers. 

Table 1. White Paper Peer Review Commenters

Commenter Affiliation White Paper Reviewed 

David Allen University of Texas All 

Ramon Alvarez, Robert Harriss, 

and David Lyon 

Environmental Defense Fund All 

Joe Cardena XTO Energy, Inc. Oil Well Completions 

Ned Jerabek New Mexico Environmental 

Department 

Oil Well Completions, Compressors 

and Pneumatic Devices 

Karen Olsen Southwestern Energy Oil Well Completions 

Steven Prince Division of Natural Resources, 

Navajo Nation 

Oil Well Completions 

Matthew Harrison URS Corporation Upstream Leaks 

Doug Jordan Southwestern Energy Upstream Leaks 

David Picard Clearstone Engineering Ltd. Upstream Leaks 

Curtis Taipale Colorado DPHE Upstream Leaks 

Gary Reeves Pioneer Natural Resources Compressors 

John Cordaway Transcanada Corporation Compressors 

Jim Bolander Southwestern Energy Pneumatic Devices and 
3 

Liquids Unloading 

Carrie Reese Pioneer Natural Resources Pneumatic Devices 

Gordon Reid Smith Independent Consultant 

BP America Production Co. 

Liquids Unloading 

2.0. Oil Well Completions and Ongoing Production 

2.1 Description of Process: 

The white paper addresses VOC emissions estimates and control technologies completions and 

associated gas from ongoing production at hydraulically fractured oil wells. Hydraulic fracturing is one 

technique for improving oil and gas production where the reservoir rock is fractured with very high 

pressure fluid, typically a water emulsion with a proppant (generally sand) that “props open” the 

fractures after fluid pressure is reduced. Completion operations with hydraulic fracturing are conducted 

to either bring a new oil well into the production phase or to maintain or increase the well’s production 

capability (sometimes referred to as a recompletion). Well completions with hydraulic fracturing include 

multiple steps after the well bore hole has reached the target depth. These steps include inserting and 

cementing-in well casing, perforating the casing at one or more producing horizons, and often 

hydraulically fracturing one or more zones in the reservoir to stimulate production. Surface components, 

including wellheads, pumps, dehydrators, separators, tanks, and are installed as necessary for production 

to begin. 

The emissions from completions are a result of the backflow of the fracture fluids and reservoir 

gas at high volume and velocity necessary to lift excess proppant and fluids to the surface. This 

comingled fluid stream (containing produced oil, natural gas and water) flows from each drilled well to 

a respective vertical separator and heater/treater processing unit. Phase separation is the process of

removing impurities from the hydrocarbon liquids and gas to meet sales delivery specifications for the

oil and natural gas. If infrastructure is present, produced gas can be metered to a sales pipeline. If

infrastructure is not available, the produced gas is frequently sent to combustion devices for destruction 

(e.g., flares) or is vented to the atmosphere. 

Associated gas is the term typically used for natural gas produced as a by-product of the 

production of crude oil. Industry publications typically refer to associated gas as gas that is coproduced 

with crude oil while the well is in the production phase and is vented directly to the atmosphere or is 

flared. Therefore, associated gas can include gas that is produced during flowback associated with 

completion activities and gas that is emitted from equipment as part of normal operations, such as 

natural gas driven pneumatic controllers and storage vessels. 

2.2 Emissions Data 

The white paper describes the processes used to estimate emissions from oil well completions. 

Because limited direct measurement of emissions has been conducted, these processes rely on data 

produced for other purposes. These data include estimated gas produced during completions, gas 

produced by the well over a certain production period, gas composition data from analysis of various gas 

streams, and data on duration of completion cycles. Various elements of these data are provided in 

various studies and information sources presented below.

Source of Data Fort Berthold Federal Implementation Plan, 2012 

Emissions Source 

Description

From 154 synthetic minor permit applications for oil wellheads, heater/treaters and 

storage tanks, representing 533 production wells, five major operators 

Type of Data: Estimated VOC emissions from above sources, oil production data, number of storage 
4 

tanks, combustors, flares and presence of a pipeline, cost data for combustion and REC 

controls, gas composition data, projected number of new wells pad per year between 201 

and 2019 

Emissions Estimation/ 

Measurement 

Measured gas composition data; calculated VOC emissions using gas composition 

and oil production data and emission factors for oil wells from GRI/EPA study. 

Methane or VOC 

emission factors/ 

emissions findings 

No new emission factors developed. However, the study of the data provided an 

opportunity to analyze production data and emissions information to determine potential 

completion emissions. 

Applicability to ONG 

Sector

Although a large data set, data was regionally based in two formations. Gas composition 

and production had high variability and also may differ from what would be found 

nationally. 

Source of Data ERG/ECR Contractor Analysis of HPDI® Data, 2013 

Emissions Source 

Description 

Hydraulically fractured oil wells 

Type of Data: HPDI data on number of hydraulically fractured oil well completions, CY 2011, 

average daily flow of oil, 192 data points representing county level average daily 

natural gas production at 5,754 oil well completions 

Emissions Estimation/ 

Measurement 

Using HPDI oil well data and GRI/EPA gas composition data, calculated methane and 

VOC emissions from 7 and 3 day completion durations. Using data from Colorado, 

Texas and Wyoming state reported data, calculated percentage of existing wells 

undergoing recompletion annually. 

Methane or VOC 

emission factors/ 

emissions findings 

Average gas production of 262 Mcf per well per day. Uncontrolled VOC emissions 

were 20 tons per completions event (7-day) and 6.4 tons per event (3-day). Methane 

emissions were 24 tons per vent (7-day) and 7.7 tons per event (3-day). Nationwide 

emissions were estimated using well count data from HDPI. Estimated that 0.5% of 

existing oil wells undergo recompletion annually. 

Applicability to ONG 

Sector 

Gas production from hydraulically fractured oil wells. Assumes no control applied. 

Nationwide level of use of RECs or combustors on oil well completions was not 

available. 

Source of Data Environmental Defense Fund Analysis of HPDI® Data, 2014 

Emissions Source 

Description 

Oil well completions in Bakken, Eagle Ford and Wattenberg formations. 

Type of Data: HPDI data: 3,694 oils in Bakken, 1,797 oil wells in Eagle Ford, and 3,967 oil wells in 

Wattenberg, initial gas production, natural gas methane content. 

Emissions Estimation/ 

Measurement 

Estimated uncontrolled demission from oil well completions for each formation 

Methane or VOC 

emission factors/ 

emissions findings 

10.5 tons of methane per completion event for Wattenberg, 19.8 tons of methane per 

completions event for Bakken and 27.2 tons of methane per completion event for Eagle 

Ford. 

Applicability to ONG 

Sector 

Re-evaluation of HDPI data indicating similar findings as other analysis conducted by 

EPA, with the exception of formation specific focus. 

Source of Data Measurements of Methane Emissions at Natural Gas Production Sites in the United 

States, 2013 

Emissions Source 

Description 

Academic/industry study to measure emissions from several oil and natural gas 

production sources, including gas and oil well completions 

Type of Data: 6 oil wells - oil produced, gas produced, gas-to-oil ratio, gas composition, type of 

emissions controls used, percent reduction for the controls used, and duration of 

completion events 

Emissions Estimation/ 

Measurement 

Measured oil production and gas production, calculated methane and VOC emissions, 

measured gas composition and calculated emission reduction percentage for controls 
5 

used. Assumed a gas to oil ratio of 12,500 scf/barrel to distinguish oil wells from gas 

wells. 

Methane or VOC 

emission factors/ 

emissions findings 

Average duration 72 hours or 3 days. Average uncontrolled methane was 213 tons and 

average controlled was 3.2 tons. One well controlled using a REC reported 98.8 percent 

reduction. 

Applicability to ONG 

Sector 

Only measured data available for completion events. However, sample size very small. 

Source of Data Methane Leaks from North American Natural Gas Systems, 2013 

Emissions Source 

Description 

Hydraulically fractured oil wells drilled in 2010 or 2011 in Eagle Ford, Bakken and 

Permian formations 

Type of Data: HPDI data: oil well counts, oil production, gas production 

Emissions Estimation/ 

Measurement 

O'Sullivan method, peak gas production (normally within first month) is converted to a 

daily rate and emissions increase linearly over the first 9 days of completion until peak 

rate is reached. 

Methane or VOC 

emission factors/ 

emissions findings 

Eagle Ford, uncontrolled methane 93 tons per event, Bakken 31.9 tons per event and 

Permian 31.9 tons per event. 

Applicability to ONG 

Sector 

Contrast to calculation used in ERG/ECR analysis using same type of data. 

The white paper also discusses two approaches that could potentially be used for estimating 

associated gas from oil wells. One method is using the gas-to-oil ratio of the well to develop an 

emission factor that would be applied to know oil production data. However, the dynamics of gas 

reduction over the life of oil production would need to be considered. The second approach be to use 

gas production data reported by the well for economic or regulatory reasons. However, the data would 

not provide insight as to what was capture/controlled or vented. The two sources of data discussed for

associated gas were the Greenhouse Gas Reporting Program and a North Dakota flaring study. Neither 

of those sources were noted as providing information that would be nationally representative or robust

enough to determine emissions of associated gas. 

2.3 Mitigation Approaches 

Approach Reduced Emission Completions (REC) 

Description A well completion following fracturing or refracturing where gas flowback that is otherwise 

vented is captured, cleaned, and routed to the flow line or collection system, reinjected into the 

well or another well, used as an onsite fuel source, or used for other useful purpose that a 

purchased fuel or raw material would serve, with no direct release to the atmosphere 

Applicability Applicable at most gas producing oil wells. Limitations include proximity of the wall to a gas 

pipeline, sufficient volume and pressure of produced gas, and inert gas concentration in flowback 

gas. 

Costs Per Natural Gas STAR study, average costs for a REC average cot so $4,146 per day. Total cost 

depends on length of flowback period. A 7-day completion would cost $29,022. These costs do 

not consider gas savings. 

Efficacy and 

Prevalence

Depends on well and reservoir characteristics, however, per Natural Gas STAR study, the 

efficiency is estimated at 90 percent emissions reduction. No significant data is available on the 

prevalence of the use of RECs for oil well completions. 

Approach Completion Combustion Devices 

Description High temperature oxidation of hydrocarbons in the gas stream. Include flares and enclosed 

combustors. 

Applicability Generally applicable to all oil well sites. 

Costs Average cost for an enclosed combustor $18,092. 

Efficacy and 95 percent reduction with a continuous ignition source. Generally one combustion device 
6 

Prevalence theoretically can service multiple wells. Some data suggests common use in the industry. 

2.4 Peer Review Opinion 

The peer reviewers generally agreed with the use of gas production data as a reasonable basis for 

estimating emissions but differed significantly on how that parameter could be used. Most commenters 

indicated that annual production was not appropriate and initial production was also not appropriate. 

Reviewers noted that the flowback gas has different dynamics and concentration than production gas 

because of the change in the reservoir after removal of fracking fluids from the well. All commenters 

indicated that a more diligent effort should be put into determining the duration of flowback, specific to 

oil wells as it determines both emissions and costs for application of RECs and the effectiveness of 

them, and that duration of flowback period at oil wells used in the EPA estimates is unsupported with 

data in the white paper. Reviewers reiterated the high variability of all parameters need to estimate 

emission from completions and the need to further study and establish data that directly relates to the 

operation. Reviewers pointed out that EPA has misconstrued recompletion versus refracturing and that 

the latter is what they are actually addressing in the white paper. Most reviewers indicated that industry 

is currently controlling some emissions from completions and noted methods to more fully quantify 

those data. For the most part, industry reviewers believed the emissions estimates to be overstated and 

the environmental and state reviewers noted that they were understated. 

3.0 Fugitive Emissions (Leaks) 

3.0 Oil and Natural Gas Sector Leaks (Fugitive Emissions) 

3.1 Description of Process: 

The emissions data and the mitigation techniques presented in the White Paper are applicable to 

natural gas fugitive emissions from natural gas production, processing, transmission, and storage. Some 

of these emissions estimates and mitigation techniques are also applicable to oil wells that co-produce 

natural gas. For the purposes of the White Paper, fugitives were defined as VOC and methane emissions 

that occur at onshore facilities upstream of the natural gas distribution system (i.e., upstream of the city 

gate). This includes fugitive emissions from natural gas well pads, oil wells that co-produce natural gas, 

gathering and boosting stations, gas processing plants, and transmission and storage infrastructure. 

Potential sources of fugitive emissions from these sites include agitator seals, compressors seals, 

connectors, pump diaphragms, flanges, hatches, instruments, meters, open-ended lines, pressure relief 

devices, pump seals, valves, and improperly controlled liquids storage. Emissions from equipment 

intended to vent as part of normal operations, such as gas driven pneumatic controllers, are not 

considered leaks. The definition of fugitive emissions in the White Paper was derived by reviewing the

various approaches taken in the available literature. 

 Fugitive emissions occur through many types of connection points (e.g., flanges, seals, threaded 

fittings) or through moving parts of valves, pumps, compressors, and other types of process equipment.

Changes in pressure, temperature and mechanical stresses on equipment may eventually cause them to 

leak. Fugitive emissions can also occur when connection points are not fitted properly, which causes 

leaks from points that are not in good contact. Other leaks can occur due to normal operation of 

equipment, which, over time, can cause seals and gaskets to wear. Weather conditions can also affect the 

performance of seals and gaskets that are intended to prevent leaks. Lastly, fugitive emissions can occur 

from equipment that is not operating correctly, such as storage vessel thief hatches that are left open or 

separator dump valves that are stuck open. 

 
7 

3.2 Emissions Data 

Source of Data Protocol for Equipment Leak Estimates, 1995 

Emissions Source 

Description

Provides standard procedures for estimating TOC mass emissions from leaks at refineries, 

marketing terminals, oil and gas production operations and SOCMI facilities. 

Type of Data: Correlation equations and emission factors were developed from leak data collected for 

valves, pumps, compressors, pressure relief valves, connectors, flanges and open-ended 

lines. Development of emission factor and correlation equations for the oil and natural gas 

production facilities were derived from data from 6 gas plants and from leak emission 

measurement data from 24 oil and natural gas production facilities. 

Estimation/ 

Measurement 

Provides 4 approaches for estimating leak mass emissions from these sites; average emission 

factor, screening range, EPA correlation and unit specific correlation approach. 

Methane or VOC 

emission factors/ 

emissions findings 

The emission factors and correlation equations provide equipment leak emissions in units of 

kilograms TOC/hr per individual piece of equipment. Methane and VOC would be estimated 

using composition and weight ratios. 

Applicability to 

ONG Sector

The data available in the Protocol document are for natural gas production facilities. Based 

on the data available, only the average emission factor approach could be used for 

estimating methane and VOC leak emissions. 

Source of Data GRI/EPA Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, 

1996 

Emissions Source 

Description 

Provides an estimate of annual methane emissions from leaks from the natural gas 

production sector using component counts and methane emission factors. 

Type of Data: Correlation equations and emission factors were developed from leak data collected for 

valves, pumps, compressors, pressure relief valves, connectors, flanges, open-ended lines 

and sampling connections. 

Estimation/ 

Measurement 

All components screened following EPA Method 21. GRI Hi-Flow used to determine 

emission factors for some offshore production sources. For onshore natural gas production, 

facilities were broken into eastern and western categories, to account for regional differences 

in methane content of the natural gas. 

Methane or VOC 

emission factors/ 

emissions findings 

The study estimated that 15,512 million standard cubic feet per year (MMscf/yr) of methane 

are emitted as leaks from 271,928 onshore natural gas production wells in the U.S. for the 

1992 base year. 

Applicability to 

ONG Sector 

The study used two approaches to estimate component emissions for the onshore natural gas 

production, offshore natural gas production, natural gas processing, natural gas transmission 

and natural gas storage segments. 

Source of Data Greenhouse Gas Reporting Program (GHGRP), 2013 

Emission Source 

Description: 

Requires facilities to report data from large emission sources across a range of industry 

sectors, as well as suppliers of certain GHGs and products that would emit GHGs if released 

or combusted. 

Type of Data: Covers a subset of national emissions, as facilities are required to submit annual reports only 

if total GHG emissions are 25,000 metric tons CO2e or more. Facilities use uniform 

methods prescribed by the EPA to calculate GHG emissions, such as direct measurement, 

engineering calculations, or emission factors. 

Estimation/ 

Measurement 

Methods for calculating emissions from leaks depend on industry segment. Onshore 

production facilities use population counts and population emission factors. Facilities in the 

onshore gas processing and gas transmission segments use counts of leaking components 

and leak emission factors. 

Methane or VOC 

emission factors/ 

emissions findings 

For the 2012 reporting year, reported methane emissions from leaks from onshore petroleum 

and natural gas production were 364,453 MT, onshore natural gas processing were 13,527 

MT, and onshore natural gas transmission compression were 15,868 MT. 

Applicability to 

ONG Sector 

The 2012 GHG data for Petroleum and Natural Gas Systems was collected under the 

GHGRP. 

Source of Data Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (U.S. EPA, 2014) 

Source Description: Tracks total U.S. GHG emissions and removals by source and by economic sector over a 

time series, beginning with 1990. The GHG Inventory includes estimates of methane and 

CO2 for natural gas and petroleum systems. 
8 

Type of Data: Covers all equipment that process or transport natural gas from oil and gas production sites. 

The segment is broken into six regions and includes estimates for gas wells, separation 

equipment, gathering compressors, gathering pipelines, drilling and well completions, 

normal operations, condensate tank vents, well workovers, liquids unloading, vessel 

blowdowns, and process upsets. 

Estimation/ 

Measurement 

Emission factors from the GRI/EPA adapted in the 2014 GHG Inventory for each of the 

NEMS regions based on-specific methane content in produced natural gas. 

Methane or VOC 

emission factors/ 

emissions findings 

Estimated 332,662 MT of potential methane leak emissions from gas wells and field 

separation equipment from natural gas production activities in 2012; 33,681 MT of potential 

methane emissions from gas processing leak emissions and 114,348 MT of potential 

methane emissions from gas transmission leak emissions; and estimates that potential 

emissions from leaks in production, processing and transmission are approximately 480,691 

million MT of methane or about 8% of overall potential methane emissions from oil and 

gas. 

Applicability to 

ONG Sector 

Facility-level data reported, limited due to reporting threshold. 

Source of Data Measurements of Methane Emissions at Natural Gas Production Sites in the United States, 

2013 

Emissions Source 

Description 

An academic study to gather methane emissions data at onshore natural gas sites in the U.S. 

Type of Data: Leak emissions from piping, valves, separators, wellheads and connectors. 

Estimation/ 

Measurement 

Identification of fugitives using OGI camera. The flow rate and the concentration of the 

leaks were measured using a Hi-Flow SamplerTM and the mass emission rate calculated. 

Based on the gas composition, the percentage of carbon accounted for by methane in the 

sample stream was determined. 

Methane or VOC 

emission factors/ 

emissions findings 

Average values of leak emissions per well reported are comparable to the average values of 

potential emissions per well for gas wells, separators, heaters, piping and dehydrator leaks 

(0.072 scf methane/min/well) from the 2013 GHG Inventory, calculated by dividing the 

potential emissions in these categories in the 2013 GHG Inventory by the number of wells. 

Applicability to 

ONG Sector 

Limited sample size, however, data can be used as benchmark. 

Source of Data City of Fort Worth Natural Gas Air Quality Study, 2011 

Emissions Source 

Description 

Conducted on behalf of City to determine level of air pollution is being released by natural 

gas exploration in Fort Worth, the compliance status of the sites, offsite impacts of 

emissions, and adequacy of city-mandated setbacks. 

Type of Data: Collected ambient air monitoring and direct leak and vented emissions measurements and 

performed air dispersion modeling using data from 375 well pads, 8 compressor stations, a 

gas processing plant, a saltwater treatment facility, a drilling operation, a hydraulic 

fracturing operation, and a completion operation. 

Estimation/ 

Measurement 

Identification and measurement with OGI, TVA, a Hi-Flow SamplerTM and stainless steel 

canisters. Measurements for each site and 10% of the total valves and connectors and the 

other components by TVA to determine leaks at or above 500 ppmv. Gas samples from 

selected leaks were collected in stainless steel canisters for VOC and HAP analysis by a gas 

chromatograph/mass spectrometer (GC/MS). 

Methane or VOC 

emission factors/ 

emissions findings 

Estimated the total organic emissions to be 20,818 tons per year or 18,819 Mg/yr, with well 

pads accounting for more than 75% of the total emissions. Hydrocarbons with low toxicities 

accounted for approximately 98% of the emissions. 

Applicability to 

ONG Sector 

Specific to air quality issues associated with natural gas exploration and production. Limited 

due to geographic concentration and sample size. 

Source of Data Measurements of Well Pad Emissions in Greeley, CO, 2012 

Emissions Source 

Description 

23 well pads in areas near Greeley, CO (Weld County). 

Type of Data: The average production pad consisted of 5 wells, 258 valves, 2,583 connectors, 3 condensate 

tanks, 1 produced water tank, 4 thief hatches, 5 pressure relief devices, 3 separators and 1 

enclosed combustor control device. 
9 

Estimation/ 

Measurement 

93 emission points were identified with OGI technology at the 23 production sites and 

emission rates were measured using a high volume sampler with a subset of 33 additionally 

sampled using evacuated canisters. A disproportionate number of detected emissions were 

found to be associated with storage tanks (72%). 

Methane or VOC 

emission factors/ 

emissions findings 

Authors concluded condensate tank-related emissions observed in the Greeley study were 

not effectively collected and controlled. Due to single point and instantaneous nature of the 

measurements, unknown if these uncollected emissions exceed the state allowance. 

Considering only emissions measurements with canister analysis, average methane 

emissions from all storage tanks, excluding samples of known flash emissions, were much 

lower in the Greeley study compared to the Fort Worth study. Average VOC tank related 

emissions were much higher in the Greeley compared to Fort Worth study. Non-tank 

emissions followed similar trends. 

Applicability to 

ONG Sector 

The objectives of the limited scope Greeley well pad study were to improve understanding 

of methane and speciated VOC emissions and investigate the use of commercially available 

non-invasive measurement approaches for application to wet gas production operations 

(including tank emissions). 

Source of Data Quantifying Cost-Effectiveness of Systematic Leak Detection and Repair Programs Using 

Infrared Cameras, 2013 

Emissions Source 

Description 

Components at gas processing plants, compressor stations and well sites. 

Type of Data: Leak rates, types of leaking components 

Estimation/ 

Measurement 

Identification of fugitives using OGI and measurement using a high-volume sampler. In 

some cases, an estimate (evaluated using OGI) was used to make the decision to repair. 

Methane or VOC 

emission factors/ 

emissions findings 

Study found of the 58,421 components identified in the surveys, 39,505 (68%) were either 

leaking or venting gas. Gas processing plants had the highest leak rate, followed by 

compressor stations and then well sites. The study noted that vents are the most common 

source of gas emissions from the identified emission sources, and about 40% of the vent 

emissions come from instrument controllers and compressor rod packing. 

Applicability to 

ONG Sector 

The study results show that, for the facilities in the study, gas processing plants are the most 

likely to have leaks and the most likely to have large leaks, followed by compressor stations, 

and, lastly, well sites. 

Source of Data Mobile Measurement Studies in Colorado, Texas, and Wyoming, 2012 

Emissions Source 

Description 

Oil and natural gas facilities (well pads and compressor stations) 

Type of Data: OTM 33A readings for methane and canister analysis for VOC in the Fort Worth area, WY, 

93 and CO, and TX. 

Estimation/ 

Measurement 

OTM 33A ambient air sampler, some canisters were analyzed for VOC. 

Methane or VOC 

emission factors/ 

emissions findings 

Preliminary results show median methane emission rates of 0.21 g/s, 0.43 g/s and 0.79 g/s 

and VOC emission rates of 0.16 g/s, 0.04 g/s and 0.30 g/s for the CO, TX, and WY studies, 

respectively (excluding Eagle Ford). 

Applicability to 

ONG Sector 

Ambient air sampling technique can show presence, however, not quantifiable as a sourcespecific tool. 

Source of Data Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil 

and Natural Gas Industries, 2014 

Emissions Source 

Description 

22 methane emission sources in the oil and natural gas industry including well site leaks 

(includes heaters, separators, dehydrators and meters/piping) and pipeline leaks. 

Type of Data: Analysis if existing 2013 GHG Inventory for methane emissions data for the oil and natural 

gas sector revised to include updated information from the GHGRP and other studies. 

Estimation/ 

Measurement 

The 2011 baseline methane inventory wellhead emission factor for well sites, 97.6 scf/day 

used to estimate the total methane leak emissions from well sites. Leak emissions from 

heater, separators, dehydrators, and meters/piping in the natural gas production sector were 

calculated using the GRI/EPA factors. 

Methane or VOC 

emission factors/ 

emissions findings 

Estimated14 billion cubic feet (264,000 MT) of methane emissions from wellheads in 

comparison; 15 billion cubic feet (283,000 MT) from heaters, separators, dehydrators and 

meters/piping; and 3 billion cubic feet (56,600 MT) from processing facilities. 
10 

Applicability to 

ONG Sector 

Some discussion of emissions levels and potentially cost-effective approach to reduce 

methane emissions from the industry. 

Source of Data Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas 

Processing Plants, 2002 and Cost-Effective Directed Inspection and Maintenance Control 

Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations 

and Well Sites,, 2006 

Emissions Source 

Description 

4 gas processing plants in the western U.S. and 5 gas processing plants, 12 well sites, and 7 

gathering stations in the U.S 

Type of Data: Screening data or engineering calculation of gas flows into the vent and flare systems; 

Screening data on 101,193 individual gas service components were screened, along with 5 

process vents, 28 engines, 7 process heaters, and 6 flare/vent systems and screening data for 

gas service equipment components at 24 sites 

Estimation/ 

Measurement 

Bubble tests with soap solution, portable hydrocarbon gas detectors, and ultrasonic leak 

detectors using a 10,000 ppm leak definition. Leak rates were measured using a Hi-FlowTM 

Sampler or bagging or other direct measurement techniques. 

Methane or VOC 

emission factors/ 

emissions findings 

Approximately 2.6 percent of screened components were determined to be leaking. The 

study states that “components in vibrational, high-use or heat- cycle gas service were the 

most leak prone.” The majority of the leaks were attributed to a relatively small number of 

leaking components. 

Applicability to 

ONG Sector 

Component specific information and provided an analysis of the payback periods for fixing 

the identified leaks. 

3.3 Mitigation Approaches 

Approach Portable Analyzers 

Description A portable monitoring instrument is used to detect hydrocarbon leaks from individual pieces 

of equipment. 

Applicability Portable analyzers can be used to estimate the mass emissions leak rate by converting the 

screening concentration in ppm to a mass emissions rate by using the EPA correlation 

equations from the Protocol for Equipment Leak Emission Estimates. The correlation 

equations in the Protocol can be used to estimate emissions rates for the entire range of 

screening concentrations, from the detection limit of the instrument to the “pegged” 

screening concentration, which represents the upper limit of the portable analyzers. 

Costs Costs vary based on the type of analyzer used to measure leak concentrations. The 

documentation for the EPA National Uniform Emission Standards for Equipment Leaks (40 

CFR part 65, subpart J) provides a cost of $10,800 for a portable monitoring analyzer (RTI, 

2011). Additional costs would also include labor costs associated with performing the screening 

and would depend on the number of components screened. 

Efficacy and 

Prevalence

The portable analyzers must be calibrated using a reference gas containing a known compound 

at a known concentration. Methane in air is a frequently used reference compound. The portable 

monitoring instruments operate on a variety of detection principles, with the three most common 

being ionization, IR absorption and combustion. The typical types of portable analyzers used for 

detecting leaks from components are OVAs and TVAs. 

Approach Optical Gas Imaging (IR Camera) 

Description Uses spectral wavelength filtering and an array of IR detectors to visualize the IR absorption of 

hydrocarbons and other gaseous compounds and operates much like a consumer video 

camcorder and provides a real-time visual image of gas emissions or leaks to the atmosphere. 

Applicability The OGI system provides a technology that can potentially reduce the time, labor and 

cost of monitoring components. 

Costs The capital cost of purchasing an OGI system is estimated to be $85,000 to $124,000. Provides 

an analysis of cost of use in the field which ranged from The EPA estimated that the OGI can 

monitor 1,875 to 2100 components or pieces of equipment per hour and for every hour of video 

footage, the operator would spend an additional 1.4 hours conducting activities for calibration, 

OGI adjustments, tagging leaks and other activities.. 

Efficacy and 

Prevalence 

Can identify hydrocarbon plumes from components and equipment only, no capability to 

quantify emission rate. Cost depend on site and overall approach of survey. 
11 

Approach Acoustic Leak Detector 

Description Acoustic leak detectors are used to detect the acoustic signal that results when pressurized gas 

leaks from a component. Generally, two types of acoustic leak detection methods are used; high 

frequency acoustic leak detection and ultrasound leak detection. 

Applicability Can be used at most facilities in the sector. 

Costs No cost data for acoustic leak detectors were available in the studies or research documents. 

Efficacy and 

Prevalence 

Acoustic detectors do not measure leak rates, but do provide a relative indication of leak size 

measured by the intensity of the signal. A study measured leaks using the VPAC device and 

high volume sample to compare the readings from the two devices. No statistically significant 

correlation between the VPAC and the direct flow measurements. They determined that the 

VPAC method was not considered to be an accurate alternative to direct measurement for the 

sources tested. 

Approach Ambient/Mobile Monitoring 

Description A mobile measurement approach to investigate a variety of source emissions and air quality 

topics. 

Applicability For oil and natural gas applications, a vehicle can be equipped with at minimum a methane 

measurement instrument and GPS to facilitate discovery of previously unknown sources and in 

more advanced forms, provide information on source emission rates. 

Costs Mobile measurement instrument packages can range in cost from approximately $20,000 - 

$100,000 depending on the capability of the package. 

Efficacy and 

Prevalence 

Mobile leak detection techniques can cover large survey areas and can be particularly useful in 

identifying anomalous operating conditions (e.g., pipeline leaks and well pad malfunctions) in 

support of onsite OGI and safety programs. Impacted by weather conditions and line-of sight 

obstacles. 

Approach Repair - Quantifying Cost-Effectiveness of Systematic Leak Detection and Repair Programs 

Using Infrared Cameras, 2013, Identification and Evaluation of Opportunities to Reduce 

Methane Losses at Four Gas Processing Plants, 2002 and Cost-Effective Directed Inspection 

and Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Gathering 

Compressor Stations and Well Sites, 2006. 

Description Three studies were conducted to evaluate the cost effectiveness of leak detection and repair at 

natural gas processing plants and upstream compressor stations and well sites. Studies focused 

on gas savings as factor in economic incentive to identify and repair leaks 

Applicability Applicable for natural gas processing plants and compressor stations and well sites. 

Costs Cost of the monitoring (estimated to be $600 to $1,800 per facility, and repair, when 

considering economic benefits of gas savings, is less that the survey cost. 

Efficacy and 

Prevalence 

Over 95% of total natural gas losses can be reduced cost-effectively The studies had similar 

conclusions and that a leak is found it is almost always economic to repair it. 

3.4 Peer Review Opinion 

The primary peer review comments generally included that the white paper does not provide an 

integrated synthesis of the lessons from the cited literature sources; should provide comparisons and 

conclusions about the differences between all sources; the EPA has rendered no technical opinion on the 

underlying studies and reports; improperly defines leaks; studies referenced by the white paper appear to 

establish an emission rate for various types of leaking components, but these emission rates are applied 

based on an estimated component count, and therefore yields a “potential” emission rate and not an 

actual emission rate; the UT study did include components measured with zero emissions in the 

development of an average emission rate; however, only the components measured were included in the 

averaging and not the total population of components at the location, also, the “average emissions rate” 

is applied to each component, which presumes that every component is leaking at that average rate for 

the entire estimation period, yielding a potential emission value and not an actual emissions value and 

improperly inflates both the emissions associated with leaks as well as estimated “cost recovery;” the

white paper does not address the uncertainty in the average facility-level or process unit-level 

component counts, or the challenges of getting accurate component counts; no indication is given 
12 

regarding the accuracy of the leak-rate correlation and different emission factor methods and how the 

accuracy is impacted by the number of components considered (other than indicating they should not be 

applied to individual components); the white paper fails to recognize the AVO inspection; contend the 

acoustical method does not distinguish between natural gas leaks and leaks of other types of gases; the 

variety of equipment configurations that can be used in mobile measurement studies is not reflected the 

white paper; did not address area and building monitoring systems, use of odorants, soap solutions and

mass balance techniques for leak detection; the URS/UT study was conducted at a compressor station 

and the vibrations associated with compression may influence the ability of the acoustic sensor to detect 

and quantify leaks and results of the study should not be generalized. 

4.0 Pneumatic Devices 

4.1 Pneumatic Controllers 

4.1.1 Description of Process 

 A pneumatic controller is an automated instrument used to control a valve for the purpose of 

maintaining a process condition such as liquid level, pressure, pressure difference or temperature. 

Controllers may be powered by pressurized natural gas or by other sources of power, such as solar, 

electric and instrument air. In many situations, across all segments of the oil and gas industry, pneumatic 

controllers make use of the available high-pressure natural gas. These natural gas-driven pneumatic 

controllers may be characterized by their emissions characteristics as follows: 

• Continuous bleed, which continuously vent natural gas and have been further divided between 

low bleed (bleed or emission rate ≤ 6 standard cubic feet per hour (scfh)) and high bleed (bleed 

rate > 6 scfh).

• Intermittent, which emit natural gas only when actuated. 

• Zero bleed, which are self-contained and release gas to a downstream pipeline instead of to the 

atmosphere. 

4.1.2 Emissions Data 

Source of Data Methane Emissions from the Natural Gas Industry, 1996 

Emissions Source 

Description 

Pneumatic controllers (PCs) in the natural gas production, processing and transmission 

industry segments. 

Type of Data: Data on emissions and inventory of PCs at facilities in each studied segment 

extrapolated to estimate national methane emissions in 1992. 

Estimation/ 

Measurement 

Combination of measured emissions, manufacturers’ data and site visits to estimate 

emission and activity factors for each industry segment 

Methane or VOC emission 

factors/ emissions findings 

Production: 125,925 scfy/PC x 249,111 PCs = 592,349 MT methane/yr 

Processing: 165,000 scfy/facility x 726 facilities = 2,262 MT methane/yr 

Transmission: 162,197 scfy/PC x 87,206 PCs = 267,093 MT methane/yr 

Applicability to ONG 

Sector 

Data specific to ONG segments that were studied 

Source of Data Estimates of Methane Emissions from the U.S. Oil Industry, 1999 

Emissions Source 

Description 

PCs at tank batteries in the oil production industry segment, characterized as high bleed 

and low bleed. 

Type of Data: Used bleed rates from the GRI/EPA study above and from Natural Gas STAR along 

with estimated inventory to estimate 1995 national methane emissions. 

Estimation/ 

Measurement 

Assumed emission rate for high bleed PCs at the “generic” rate from GRI/EPA study 

above; assumed default emission rate for low bleed PCs from Natural Gas STAR. 

Assumed 35% high bleed and 65% low bleed based on the split between continuous and 

intermittent PCs found in GRI/EPA. 

Methane or VOC emission 

factors/ emissions findings 

High bleed: 345 scfd, 157,581 PCs, 376,000 MT methane/yr 

Low bleed: 35 scfd, 292,650 PCs, 69,900 MT methane/yr 
13 

Applicability to ONG 

Sector 

PC inventory estimated based on oil production industry segment data; PC emission 

rates based on rates from NG production industry segment. 

Source of Data Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012,2014 

Emissions Source 

Description 

PCs in natural gas production, processing, transmission and storage segments and the 

petroleum production segment. 

Type of Data: National methane emissions estimated for each segment; regional “potential” emissions 

for NG production. Emissions factors based on EPA/GRI study. 

Estimation/ 

Measurement 

PC emission factors trace back to EPA/GRI study, with regional factors for NG methane 

content. Inventory of PCs in each segment based on ratios of PCs to activity counts. 

“Potential” emissions then corrected based on reported Natural Gas STAR reductions to 

get net emissions. 

Methane or VOC emission 

factors/ emissions findings 

2012 NG and oil production: 769,522 MT methane net 

2012 NG processing: 1,923 MT methane (potential – no NG STAR correction) 

2012 NG transmission and storage: 249,483 MT methane net 

Applicability to ONG 

Sector 

PC emission rates and inventory specific to ONG sector. 

Source of Data Greenhouse Gas Reporting Program, 2013 

Emissions Source 

Description 

PCs in three segments: onshore petroleum and NG production, onshore NG 

transmission compression, and underground NG storage. 

Type of Data: GHGRP requires source-specific emissions reports from all ONG facilities with GHG 

emissions ≥ 25,000 MT CO2e, which is a subset of all facilities. 

Estimation/ 

Measurement 

Facilities determine the number of each type of PC and apply emission factors. 

Emission factors are based on a 2009 API document, which in turn is based on the 

GRI/EPA study. 

Methane or VOC emission 

factors/ emissions findings 

2012 Petroleum and NG production: 417 facilities; 861,224 MT methane 

2012 NG transmission: 330 facilities; 7,582 MT methane 

2012 NG storage: 38 facilities; 4,493 MT methane 

Applicability to ONG 

Sector 

Annual emissions data specific to ONG sector, but only from a subset of all facilities. 

Source of Data Measurements of Methane Emissions at Natural Gas Production Sites in the US, 2013 

Emissions Source 

Description 

PCs in the NG production industry segment. 

Type of Data: Measurement data for a sample of 305 pneumatic controllers located at 150 distinct 

natural gas production sites in four production regions (Appalachian, Gulf Coast, 

Midcontinent, and Rocky Mountain) 

Estimation/ 

Measurement 

NG emission rates determined using a portable instrument and converted to methane 

rates based on site-specific NG composition. Estimate of 2011 national methane 

emissions based on the number of PCs used in the GHG Inventory for 2011. 

Methane or VOC emission 

factors/ emissions findings 

2011 NG production: 570,000 MT methane (with a range of 510,000 – 812,000 MT). 

Found significant unexplained geographical variability in the PC emission rates between 

production regions (greater than a factor of 10 between highest and lowest). 

Applicability to ONG 

Sector 

Direct emissions measurements from PCs in the NG production sector. Relied on 

owners for type of PCs, and only low bleed and intermittent were reported. 

Source of Data Determining Bleed Rates for Pneumatic Devices in British Columbia, 2013 

Emissions Source 

Description 

High bleed PCs at upstream ONG facilities in British Columbia 

Type of Data: Measurement data from multiple units of a number of models of PCs in British 

Columbia. Centered on high bleed PCs, defined based on emissions including both 

continuous bleed (when applicable) and emissions during activations. 

Estimation/ 

Measurement 

NG emissions rates determined using a portable instrument; not converted to methane 

rates. No attempt to estimate national or area emissions. 

Methane or VOC emission 

factors/ emissions findings 

Developed NG emission factors for numerous models of PCs and “generic” high bleed 

PCs and “generic” high bleed intermittent PCs. Regression analysis used to develop 

coefficients relating bleed rate to supply gas pressure for some models and the generics.

Applicability to ONG 

Sector 

Targeted only high bleed PCs. Did not differentiate between NG and oil applications. 
14 

Source of Data Air Pollutant Emissions from the Development, Production, and Processing of 

Marcellus Shale Natural Gas, 2014 

Emissions Source 

Description 

PCs associated with wet gas and dry gas wells. 

Type of Data: VOC emissions based on NG emission factors derived from information for high bleed 

PCs provided to Natural Gas STAR by the manufacturers. 

Estimation/ 

Measurement 

Estimated VOC emissions for the Marcellus Shale region by estimating the number of 

wet and dry wells in the region and establishing per-well NG emission factors for 2009. 

Per-well factors developed based on emissions factors and per-well PC counts from a 

2008 ENVIRON report. 

Methane or VOC emission 

factors/ emissions findings 

2009 VOC emissions, tons per producing well (95% confidence interval); Dry gas: 0.5 

(0.08 – 0.8); Wet gas: 3.5 (2.4 – 4.4) 

Applicability to ONG 

Sector 

Emission rates based on PC manufacturer specs, not field testing. Per-well PC count 

from 2008 ENVIRON report based ONG survey data. 

Source of Data Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore 

Oil and Natural Gas Industries, 2014 

Emissions Source 

Description 

PCs in the oil and NG sector. 

Type of Data: Adjusted emissions from the GHG Inventory for 2011, which is national in scope. 

Estimation/ 

Measurement 

Developed new activity and emissions factors for PCs, starting with the GHG Inventory 

for 2011 and using Allen et al., 2013. Emission factors for low bleed, high bleed, and 

two types of intermittent PCs. Added 8.6 PCs per gathering/boosting area not covered in 

the GHG Inventory 

Methane or VOC emission 

factors/ emissions findings 

Estimated methane emissions in 2011 were 491,000 MT higher than GHG Inventory 

figures. 

Applicability to ONG 

Sector 

Based on data specific to the ONG sector. 

4.1.3 Mitigation Approaches 

Approach Install Zero Bleed Controller in Place of Continuous Bleed Controller, 2012 

Description Zero bleed controllers are self-contained natural gas-driven devices that vent to the downstream

pipeline, not the atmosphere. Provide the same functional control as continuous bleed 

controllers, where applicable. 

Applicability Applicable only for relatively low-pressure control valves, e.g., in gathering, metering and 

regulation stations, power plant and industrial feed, and city gate stations/distribution

applications. 

Costs The EPA does not have cost information on this technology. 

Efficacy and 

Prevalence 

100% emission reduction, where applicable. The EPA does not have information on the

prevalence of this technology in the field; however, it is the EPA’s understanding that

applicability is limited. 

Approach Install Low Bleed Controller in Place of High Bleed Controller, 2006 

Description Low bleed controllers provide the same functional control as a high bleed devices, while 

emitting less continuous bleed emissions. 

Applicability Applicability depends on the function of instrumentation for an individual device and whether 

the device is a level, pressure, or temperature controller. Not recommended for control of very 

large valves that require fast and/or precise response to process changes. These are found most

frequently on large compressor discharge and bypass pressure controllers. 

Costs Based on information from Natural Gas STAR and supplemental research conducted for subpart

OOOO, low bleed devices cost, on average, around $165 more than high bleed versions. ICF

report assumed a cost of $3,000 per replacement based on industry comments. 

Efficacy and 

Prevalence 

Estimated average reductions: Production segment: 6.6 tpy methane; Transmission: 3.7 tpy 

methane. The EPA does not have information on the prevalence of this technology in the field. 

Approach Convert to Instrument Air, 2006 

Description Compressed air may be substituted for natural gas in pneumatic systems without altering any of 

the parts of the pneumatic control. In this type of system, atmospheric air is compressed, stored 
15 

in a tank, filtered and then dried for instrument use. Instrument air conversion requires 

additional equipment to properly compress and control the pressured air. This equipment 

includes a compressor, power source, air dehydrator and air storage vessel. 

Applicability Most applicable at facilities where there are a high concentration of pneumatic control valves 

and an operator present. Because the systems are powered by electric compressors, they require 

a constant source of electrical power or a backup natural gas pneumatic device. 

Costs System costs are dependent on size of compressor, power supply needs, labor and other 

equipment. A cost analysis is provided in Section 3.1.3 of the white paper. 

Efficacy and 

Prevalence 

100% emission reduction, where applicable. There are secondary emissions associated with 

electrical power generation. The EPA does not have information on the prevalence of this 

technology in the field. 

Approach Mechanical and Solar-Powered Systems in Place of Bleed Controller 

Description Mechanical controls operate using a simple design comprised of levers, hand wheels, springs 

and flow channels. The most common mechanical control device is the liquid-level float to the 

drain valve position with mechanical linkages. Electricity or small electrical motors (including 

solar-powered) have been used to operate valves. Solar control systems are driven by solar 

power cells that actuate mechanical devices using electric power. As such, solar cells require 

some type of backup power or storage to ensure reliable operation. 

Applicability Application of mechanical controls is limited because the control must be located in close 

proximity to the process measurement. Mechanical systems are also incapable of handling 

larger flow fluctuations. Electric-powered valves are only reliable with a constant supply of 

electricity. 

Costs Depending on supply of power, costs can range from below $1,000 to $10,000 for entire 

systems. 

Efficacy and 

Prevalence 

100% emission reduction, where applicable. The EPA does not have information on the 

prevalence of this technology in the field. 

Approach Enhanced Maintenance, 2006 

Description Instrumentation in poor condition typically bleeds 5 to 10 scfh more than representative 

conditions due to worn seals, gaskets, diaphragms; nozzle corrosion or wear; or loose control 

tube fittings. This may not impact operations but does increase emissions. Proper methods of 

maintaining a device are highly variable. 

Applicability Enhanced maintenance to repair and maintain pneumatic controllers periodically can reduce 

emissions at many controllers. 

Costs Variable based on labor, time, and fuel required to travel to many remote locations. 

Efficacy and 

Prevalence 

Natural gas emission reductions of 5 to 10 scfh. The EPA does not have information on the 

prevalence of this practice in the field. 

4.2 Pneumatic Pumps 

4.2.1 Description of Process 

 Two types of pneumatic pumps are commonly used in the oil and natural gas sector: piston and 

diaphragm. The majority of pneumatic pumps used in oil and natural gas production are used for 

chemical injection or glycol circulation. Chemical injection pumps inject small amounts of chemicals to 

limit processing problems and protect equipment. “Kimray” pumps used for glycol circulation recover 

energy from the high-pressure rich glycol/gas mixture leaving the absorber and use that energy to pump

the low-pressure lean glycol back into the absorber. 

4.2.2 Emissions Data

Source of Data Methane Emissions from the Natural Gas Industry, 1996 

Emissions Source Description Chemical injection (CI) pumps (piston and diaphragm) Glycol pumps. 

Type of Data: Data on emissions and inventory of CI pumps in NG production segment and glycol 

pumps in NG production and processing segments, extrapolated to estimate national 

methane emissions in 1992. 

Estimation/ 

Measurement 

CI pumps: Manufacturer data and limited measurements for emission rate; site visits for 

inventory and duty cycle of piston and diaphragm pumps. Glycol pumps: Manufacturer 
16 

data for emission rate; activity is NG throughput. 

Methane or VOC emission 

factors/ emissions findings 

CI pumps: 248 scfd/pump x 16,971 pumps = 29,008 MT methane. Glycol pumps, NG 

production: 206,989 MT methane. Glycol pumps, NG processing: 3,215 MT methane 

Applicability to ONG Sector Directly applicable to ONG sector; very limited emission measurement data; limited site 

visit data. 

Source of Data Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012, 2014 

Emissions Source Description CI pumps in NG and Petroleum production segments; glycol pumps in the NG 

production and processing segments. 

Type of Data: National methane emissions estimated for each segment; regional “potential” emissions 

for NG production. Emission factors based on EPA/GRI study. 

Estimation/ 

Measurement 

Pump emission factors trace back to EPA/GRI study, with regional factors for NG 

methane content. Inventory of CI pumps in each segment based on ratios of PCs to 

activity counts. “Potential” CI pump emissions for NG production then corrected based 

on reported Natural Gas STAR reductions to get net emissions. Glycol pump activity is 

estimated NG throughput by region. No correction to potential emission for glycol 

pumps or CI pumps for petroleum. 

Methane or VOC emission 

factors/ emissions findings 

2012 CI pumps in NG production: 64,570 MT methane net 

2012 CI pumps in Petroleum production: 49,973 MT methane potential 

2012 Glycol pumps in NG production and processing: 388,378 MT potential 

Applicability to ONG Sector Pump emission rates and activity levels specific to ONG sector; emissions rates based 

on 1996 GRI/EPA report. 

Source of Data Greenhouse Gas Reporting Program, 2013 

Emissions Source Description Pumps at onshore petroleum and NG production facilities. 

Type of Data: GHGRP requires source-specific emissions reports from all ONG facilities with GHG 

emissions ≥ 25,000 MT CO2e, which is a subset of all facilities. 

Estimation/ 

Measurement 

Facilities determine the number pumps and apply an emission factor of 13.3 scfh NG 

and a facility-specific NG composition factor to calculate methane 

Methane or VOC emission 

factors/ emissions findings 

2012 Pumps in onshore ONG production: 343 facilities; 135,227 MT methane. 

Applicability to ONG Sector Annual emissions data specific to ONG sector, but only from a subset of all facilities. 

Source of Data Determining Bleed Rates for Pneumatic Devices in British Columbia, 2013 

Emissions Source Description CI pumps at upstream ONG facilities in British Columbia. 

Type of Data: Measurement data from 184 CI pumps. 

Estimation/ 

Measurement 

NG emissions rates determined using a portable instrument; not converted to methane 

rates. No attempt to estimate national or area emissions. 

Methane or VOC emission 

factors/ emissions findings 

NG emission factor for piston CI pumps: 0.5917 m3/hr (~ 20.9 scfh) 

NG emission factor for diaphragm CI pumps: 1.0542 m3/hr (~37.2 scfh) 

Applicability to ONG Sector Did not differentiate between NG and oil applications. 

Source of Data Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore 

Oil and Natural Gas Industries, 2014 

Emissions Source Description CI and glycol pumps in NG production segment. 

Type of Data: Adjusted emissions from the GHG Inventory for 2011, which is national in scope 

Estimation/ 

Measurement 

Used data from the GHG Inventory for 2011 and the GHGRP, as well as EIA and GRI. 

For CI pumps, updated the count to reflect changes made to the well counts and applied 

the Natural Gas STAR estimated reductions. 

Methane or VOC emission 

factors/ emissions findings 

2011 CI pumps in NG production: 56,600 MT 

2011 Glycol pumps in NG production: 321,000 MT 

Applicability to ONG Sector Based on data specific to the ONG sector. 

4.2.3 Mitigation Approaches 

Approach Replace natural gas-assisted pump with instrument air pump, 2011) 

Description Circulation pumps in glycol dehydration units and chemical injection pumps are retrofitted with 

instrument air to drive the pumps. 

Applicability Facilities with excess capacity of instrument air or facilities that can install an air compressor 

system. Because the systems are powered by electric compressors, they require a constant source of 
17 

electrical power or a backup natural gas pneumatic pump. 

Costs The installation of the piping from the air compressor system to the pump accounts for the bulk of 

the capital cost and typically ranges from $100 to $1,000. 

Efficacy and 

Prevalence 

100% emission reduction, where applicable. The Natural Gas STAR reports typical annual methane 

savings to be 2,500 Mcf for glycol circulation pumps and 183 Mcf for chemical injection pumps. 

The EPA does not have information on the prevalence of this technology in the field. 

Approach Replace natural gas-assisted pump with solar-charged direct current pump, 2011 

Description In field settings, low volume natural gas pneumatic pumps can be replaced with solar-charged DC 

pumps. 

Applicability Low volume solar-charged pneumatic pumps are limited to approximately 5 gallons per day 

discharge at 1,000 psig. Large volume solar pumps are available with maximum output of 38 to 

100 gallons per day at maximum injection pressures of 1,200 to 3,000 psig. 

Costs The reporting partners for Natural Gas STAR stated a replacement cost of $2,000 per pump, 

including the solar panels, storage batteries and pump.

Efficacy and 

Prevalence 

100% emission reduction, where applicable. The Natural Gas STAR reports typical annual methane 

savings to be 182.5 Mcf per chemical injection pump conversion. The EPA does not have

information on the prevalence of this technology in the field. 

Approach Replace natural gas-assisted pump with electric pump, 2014 

Description In settings where a constant supply of electricity is available, natural gas pneumatic pumps can be 

replaced with electric pumps. 

Applicability These pumps require a constant source of electricity, thus, they are typically installed at processing

plants or large dehydration facilities, which are normally equipped with electricity. 

Costs Electrical pumps are estimated to cost roughly $10,000 per pump and the annual electrical usage 

cost was estimated to be $2,000 per year. 

Efficacy and 

Prevalence 

100% emission reduction, where applicable. The annual methane reduction from replacing 

pneumatic pumps with electrical pumps is estimated to be 5,000 Mcf. The EPA does not have 

information on the prevalence of this technology in the field. 

4.3 Peer Review Opinion 

Pier review commenters stated the white paper summarizes the data available at the time the 

white paper was written, with one exception – the data on pneumatic pumps reported in Allen et al. 

(2013). Allen, et al. (2013) reports statistically higher emissions for the 21 pumps on which emission

measurements were made in the Gulf Coast region (0.506±0.209 scf whole gas per pump per hour), 

compared to the 41 pumps on which emission measurements were made in the Midcontinent region 

(0.050±0.014 scf whole gas per pump per hour). Allen, et al. (2013) was not able to determine, from the 

data collected, the reasons for the regional differences in emissions, which was not reflected in the 

emission factors from the GHG Inventory for 2012 presented in Table 2-14 of the white paper. 

5.0 Compressors 

5.1 Description of Process: 

Compressors are mechanical devices that increase the pressure of natural gas and allow the 

natural gas to be transported from the production site, through the supply chain, and to the consumer.

Vented emissions from compressors occur from seals (wet seal compressors) or packing surrounding 

the mechanical compression components (reciprocating compressors) of the compressor. In the 

production segment, compressors are used at the wellhead to compress gas for fluids removal, and 

pressure equalization with gathering equipment systems. However, the primary use of compressors is 

in the natural gas processing, transmission and storage (particularly underground storage) segments of

the industry. In the oil and natural gas sector, the most prevalent types of compressors used are 

reciprocating and centrifugal compressors. 

In a reciprocating compressor, natural gas enters the suction manifold, and then flows into a 

compression cylinder where it is compressed by a piston driven in a reciprocating motion by the 

crankshaft powered by an internal combustion engine. Over the operating life of the compressor, the 
18 

rings become worn and the packing system will begin to wear, resulting in higher leak rates. 

Emissions from packing systems originate from mainly four components: the nose gasket, between 

the packing cups, around the rings and between the rings and the shaft. Typically, gases leaked from 

the packing system are vented to the atmosphere. 

Centrifugal compressors use a rotating disk or impeller to increase the velocity of the gas 

where it is directed to a divergent duct section that converts the velocity energy to pressure energy.

These compressors are primarily used for continuous, stationary transport of natural gas and are 

widely used in the processing and transmission industry segments. Centrifugal compressors are 

equipped with either a wet or dry seal configuration. Wet seals use oil around the rotating shaft to 

prevent natural gas from escaping where the compressor shaft exits the compressor casing. The oil is 

circulated at high pressure to form a barrier against compressed natural gas leakage. The circulated oil 

entrains and absorbs some compressed natural gas that may be released to the atmosphere during the 

seal oil recirculation process (degassing or off- gassing). Alternatively, dry seal compressors use the 

opposing force created by hydrodynamic grooves and springs to provide a seal. Opposing forces 

create a thin gap of high pressure gas between the rings through which little gas can leak. The rings do 

not wear or need lubrication because they are not in contact with each other. Gas emissions from wet 

seal centrifugal compressors have been found to be higher than dry seals compressors primarily due to 

the off-gassing of the entrained gas from the oil. The maintenance costs less than wet seal compressors 

because they are a mechanically simpler design, require less power, are more reliable and require less

maintenance. 

5.2 Emissions Data 

Source of Data GRI/EPA Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, 

1996 

Emissions Source 

Description

Reciprocating and centrifugal compressor seals from the natural gas production, processing, 

transmission and storage sector. 

Type of Data: Estimate of annual methane emissions from using the component method. 

Emissions 

Estimation/ 

Measurement 

Component method, average emission factors for reciprocating and centrifugal 

compressor seals and the average number of reciprocating and centrifugal compressors 

per facility to estimate the average facility emissions; emission factors based on 

screening of components using OVA and TVA. 

Methane or VOC 

emission factors/ 

emissions findings 

Production: 40 reciprocating compressor seals; emission factor 2.37 Mcfy per cylinder. 

Processing, Transmission and Storage: Both types of compressors, pressurized and nonpressurized operation modes; 599 Mcfy per seal pressurized and 116 Mcfy per seal in idle. 

Emission factors developed using time compressor is pressurized, number of seals. 

Applicability to 

ONG Sector

Presented the emissions for reciprocating and centrifugal compressors as a sum of the 

emission components from compressors. These components included methane emissions 

from compressor seals, blowdown open-ended line, pressure relief valves, starter openended line, and miscellaneous, which includes valves and connectors. Compressor 

emissions were calculated in tpy using component count per compressor. White paper 

summarized average methane emission from each segment in MT per year using GRI data. 

Source of Data Natural Gas Industry Methane Emission Factor Improvement Study, Final Report, 2011 

Emissions Source 

Description 

Focused on processes and equipment believed to contribute the greatest uncertainty to the 

emissions inventory; fugitive leaks from transmission, gathering/boosting and processing 

compressor components including vents. 

Type of Data: Implications for usefulness: quality, quantity, national, source-specific, geographic 

distribution. 

Emissions 

Estimation/ 

Measurement 

Measured using anemometer. 

Methane or VOC 

emission factors/ 

Gathering and boosting reciprocating compressor; 15 sampled, 241 mscf/yr methane 

emissions. Transmission reciprocating compressor; 5 sampled idle, 12,236 Mscf/yr 
19 

emissions findings methane and 2 sampled pressurized, 29,602 Mscf/yr methane. All centrifugal compressors; 

wet seal 9 sampled 8,137 Mscf/yr methane. 

Applicability to 

ONG Sector 

Study concluded wet seal centrifugal compressor and reciprocating compressor emissions 

were much higher than GRI/EPA factor. Noted that data should only be a benchmark, and 

not used to develop emission factors due to technical issues with measuring emissions from 

compressors. 

Source of Data Greenhouse Gas Reporting Program, 2013 

Emissions Source 

Description 

Reciprocating and centrifugal compressors in the processing, transmission and underground 

storage segments and liquid natural gas import/export and storage segments. 

Type of Data: Reported by facility, not compressor-specific, total methane emissions by compressor type, 

number of compressors. 

Emission 

Estimation/ 

Measurement 

Prescribed in subpart W, direct measurement or engineering calculations. 

Methane or VOC 

emission factors/ 

emissions findings 

Presented total number of reciprocating compressors and centrifugal compressors (with wet 

seal and without), total methane emissions for processing transmissions and storage 

segments. 

Applicability to 

ONG Sector 

Reporting threshold limits data reported; useful for overall sector characterization, not 

emission factor development. 

Source of Data Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012, 2014 

Emissions Source 

Description 

Reciprocating compressors in production through distribution. 

Type of Data: Calculated methane emissions for large and small reciprocating compressor, wet and dry 

seal centrifugal compressors in production, processing, transmission, storage segments. 

Emissions 

Estimation/ 

Measurement 

Uses GRI/EPA emission factors developed in 1996 study. 

Methane or VOC 

emission factors/ 

emissions findings 

Inventory reports nationwide 2012 based on 2012 activity and factors current emissions. 

Applicability to 

ONG Sector 

Valuable for recent activity data and overall characterization of segments. No new emission 

factor information. 

Source of Data Development of the New Source Performance Standard (NSPS) For Oil and Natural Gas 

Production, 2012. 

Emissions Source 

Description 

Reciprocating and centrifugal compressors in the natural gas sector. 

Type of Data: Used the emission factors from the GRI/EPA study and gas composition data developed for 

the NSPS subpart OOOO and methane density of 41.63 pound per Mcf. 

Emissions 

Estimation/ 

Measurement 

Calculated VOC emission rates using emission factors, gas composition methane to 

pollutant rations. 

Methane or VOC 

emission factors/ 

emissions findings 

Developed emission factors in tons/compressor/year for methane and VOC for 

reciprocating compressors and wet and dry-seal centrifugal compressors for all segments in 

the sector. 

Applicability to 

ONG Sector 

Used in the proposed Subpart OOOO. 

Source of Data Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production: 

Summary and Analysis of API and ANGA Survey Responses, 2012 

Emissions Source 

Description 

Centrifugal compressors, specifically on prevalence of wet and dry seal compressors. 

Type of Data: Compressor counts comparison to EPA 2012 GHG Inventory. 

Emissions 

Estimation/ 

Measurement 

Survey of 20 companies for specific information on number of wet seal and dry seal 

compressors in processing segment and 81 percent of compressors in production were dry 

seal. 

Methane or VOC 

emission factors/ 

No emissions factors. Survey results indicate that 79 percent were dry seal and 21 percent 

were wet seal compressors. 
20 

emissions findings 

Applicability to 

ONG Sector 

Small portion of total compressor population was included in survey results (5 percent). 

Source of Data Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil 

and Natural Gas Industries, 2014 

Emissions Source 

Description 

Targeted 22 methane emissions sources in the industry which including centrifugal and 

reciprocating compressors. 

Type of Data: Study used emissions baseline from previous ICF 2011 which updated 2013 GHG 

inventory numbers to project emissions to 2018. 

Emissions 

Estimation/ 

Measurement 

Different methods were used for each segment to project emissions to 2018 based on 

baseline. 

Methane or VOC 

emission factors/ 

emissions findings 

Emissions for 2018 were calculated and adjusted to account for effects of NSPS (subpart 

OOOO). 

Applicability to 

ONG Sector 

Based on prior studies and included no new emissions factors or emissions data. 

5.3 Mitigation Approaches 

Approach Reciprocating Compressor - Rod Packing Replacement 

Description Replacement of the compressor rod packing, replacement of the piston rod, and the refitting or 

realignment of the piston rod due to deterioration and wear. 

Applicability Applicable or all reciprocating compressor used in the sector and is currently an industry 

practice. 

Costs On average replacement is conducted every 4 years at a cost of $1620 per cylinder. Capital 

cost per compressor in production $6,480 with gas savings for life of compressor of 

$2,493. For gathering and boosting capital cost of $5,346 with gas savings of $1,669; for 

processing capital cost of $4,040 with gas savings of $1,413; for transmission capital cost 

of $5,346 with gas savings of $1,669, and for storage capital cost of $7,290 with gas 

savings of $2,276. 

Efficacy and 

Prevalence

Per compressor methane emission reductions; Production 0.158 tpy, gathering and boosting 

6.84 tpy, processing 18.6 tpy, transmission 21.7 tpy and storage 21.8 tpy. VOC emission 

reductions: production 0.04 tpy, gathering and boosting 1.9 tpy, processing 5.18 tpy, 

transmission 0.6 tpy, and storage 0.6 tpy. Prevalent practice in the industry. 

Approach Reciprocating Compressor – Gas Recovery 

Description Capture gas emissions from reciprocating compressor and route the gas back to the engine as 

fuel or capture and route to a vapor recovery unit. Gas saved can be used as fuel or flared. 

Applicability Generally applicable across the sector, particularly for processing plants due to availability 

of processes to use gas. 

Costs Cost data not available for a gas recovery system that routes back to the engine as a fuel. 

Estimated cost of additional piping to route to VRU is $2,000 assuming VRU onsite. 

Efficacy and 

Prevalence

99% reduction of emissions of gas recovered and used as a fuel for process or a VRU. 95% 

reduction if emissions are captured and flared. 

Approach Centrifugal Compressor - Dry Seals 

Description Replace wet-seal compressor with dry-seal compressor. Results in emissions reductions, higher 

reliability, and overall maintenance and operating costs. 

Applicability Applicable for most centrifugal compressors, however, not all. Due to size and certain 

applications, certain wet-seal compressors cannot be replaced with dry seal compressors. 

Costs For processing, transmission and storage, capital cost of $75,000 and annual operation and 

maintenance savings of $88,300. Processing also realizes a natural gas savings of $46,109. 

Efficacy and 

Prevalence

Methane emissions reductions per compressor is 199 tpy for processing, 110 tpy for 

transmission and storage. VOC reduction per compressor 18 tpy for processing and 3 tpy 

for transmission and storage. 

Approach Centrifugal Compressor - Wet Seal with a Flare 

Description Capture emissions and route to a flare. 
21 

Applicability Generally applicable for all segments. 

Costs For processing, transmission and storage segments, an enclosed flare capital cost is 

$67,918 with annual cost of $98,329. 

Efficacy and 

Prevalence

95% emissions reduction. Not prevalent in the industry. 

Approach Centrifugal Compressor - Wet Seal with gas recovery for use onsite 

Description Capture emissions and route to some process operation. 

Applicability Generally applicable for all segments. 

Costs For processing, transmission and storage segments, an enclosed flare capital cost is 

$22,000. For the processing segment there is an estimated annual gas savings of $44,729 

and $24,849 for the transmission and storage segments. 

Efficacy and 

Prevalence 

95% emissions reduction. Not prevalent in the industry. 

6.0 Liquids Unloading 

6.1 Description of Process: 

In most gas wells, at some point in the productive life of the well, as the reservoir pressure 

declines during production, there is a point when the pressure is not sufficient to facilitate the flow of 

accumulated water and hydrocarbon liquids to the surface along with produced gas. When this occurs, 

this accumulation of liquids can impede and sometimes halt gas production. When the accumulation of 

liquid results in the slowing or cessation of gas production (i.e., liquids loading), removal of fluids (i.e., 

liquids unloading) is required in order to maintain production. Emissions to the atmosphere during 

liquids unloading events are a potentially significant source of VOC and methane emissions. 

To restore the pressure, the operator intentionally manually vents the well to the atmosphere to 

improve gas flow. Additionally, a plunger lift system can be used which uses the well’s own energy 

(gas/pressure) to lift liquids from the tubing by pushing the liquids to the surface by the movement of a 

free-traveling plunger ascending from the bottom of the well to the surface. The plunger essentially acts 

as a piston between liquid and gas allowing the operator more control of the liquids removal process. 

6.2 Emissions Data 

Source of Data Greenhouse Gas Reporting Program, 2013 

Emissions Source 

Description

Reporting threshold (i.e., only facilities emitting 25,000 metric tons or more of CO2e; 

wells that are venting, with and without plunger lift operation; annual reporting. 

Type of Data: Nationwide, limited by reporting threshold, facilities report methane emissions and 

number of venting wells, whether or not equipped with plunger lift. 

Emissions Estimation/ 

Measurement 

Subpart W provided defines 3 methods, direct measurement and two engineering 

calculations; one with plunger lift one without. 

Emission factors/ 

emissions findings 

Data only at facility level, not well specific. 251 facilities reporting, total number of 

wells venting 58,5663, number of venting wells with plunger lifts 32,252, total methane 

emissions 276,378 MT. 

Applicability to ONG 

Sector

Generally comprehensive with exception that the limited due to reporting threshold and 

reporting requirements and methods. Facility reporting level, not well-specific. 

Source of Data Inventory of Greenhouse Gas , Emissions and Sinks: 1990-2012 (published 2013) 

Emissions Source 

Description 

Natural gas production through distribution and petroleum production through refining. 

Type of Data: Reported data on wells conducting liquids unloading, with and without plunger lifts, 

activity data, total emissions, updated by API/ANGA survey data. 

Emissions Estimation/ 

Measurement 

Uses the NEMS emission factors to percentage of wells requiring liquids unloading 

based on the API/ANGA survey data (see Data Source below). 

Methane or VOC 

emission factors/ 

emissions findings 

Provided emission factors for scfy/well, number of wells, by 6 NEMS regions of US; 

inventory estimates of liquids unloading emissions were 14 percent of overall methane 

emissions from natural gas production segment. 
22 

Applicability to ONG 

Sector 

Similar to API/ANGA data, however, applied region specific notations, possibly 

correlating more to geographic and basin applicability. 

Source of Data Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production: 

Summary and Analysis of API and ANGA Survey Responses 2012 

Emissions Source 

Description 

20 companies covering 90,000 gas wells, including gas wells that conduct liquids 

unloading. 

Type of Data: Well-level data methane emissions. 

Emissions Estimation/ 

Measurement 

Used 40 CFR part 98, subpart W engineering equations to estimate emissions using 

well-specific data on well bore volume, well pressure, venting time and gas production 

rate. 

Methane or VOC 

emission factors/ 

emissions findings 

Calculated number of wells vented with and without plunger lifts, 322,854 scfy gas 

vented per well, 254,409 scfy methane per well; authors found that EPA emission 

estimates were highly overestimated; most of the emission were produced by less than 

10 percent of the well population. 

Applicability to ONG 

Sector 

Provided well-specific data on wells that conduct liquids unloading, vent and not vent, 

with and without plunger lifts, most comprehensive data available to date on liquids 

unloading. 

Source of Data Measurements of Methane Emissions at Natural Gas Production Sites in the 

United States, 2013 

Emissions Source 

Description 

Academic study, onshore natural gas wells sites in US, compared measured emission 

rates to 2011 GHG emission inventory estimates. 

Type of Data: Length of unloading events, continuous and intermittent flow events. 

Emissions Estimation/ 

Measurement 

Direct measurement by sampling and analysis at nine well unloading events. 

Methane or VOC 

emission factors/ 

emissions findings 

Average emission 1.1 MT of methane per unloading event; supported API/ANGA 

survey findings. 

Applicability to ONG 

Sector 

Limited applicability due to small sample size. 

Source of Data Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore 

Oil and Natural Gas Industries (ICF International, 2014 

Emissions Source 

Description 

Study of economic analysis of methane emissions reduction opportunities; 22 different 

emission sources in industry, including liquids unloading. 

Type of Data: Used data from 2013 GHG inventory and UT Allen study. 

Emissions Estimation/ 

Measurement 

Updated emissions baseline to calculate emission factors for methane. 

Methane or VOC 

emission factors/ 

emissions findings 

277,000 scf/event wells with plunger lifts, 163,000 scf/venting well without plunger 

lifts; control costs for plunger lists and estimates for potential VOC emissions 

reductions from plunger lifts. 

Applicability to ONG 

Sector 

Study support use of plunger lifts as a mitigation method for emission from liquids 

unloading. 

6.3 Mitigation Approaches 

Approach Plunger Lift Systems 

Description Plunger lifts use the well’s own energy (gas/pressure) to drive a piston or plunger that travels 

the length of the tubing in order to push accumulated liquids in the tubing to the surface. 

Applicability Plunger systems have been known to reduce emissions from venting and increase well 

production. Specific criteria regarding well pressure and liquid to gas ratio can affect 

applicability. Candidate wells for plunger lift systems generally do not have adequate 

downhole pressure for the well to flow freely into a gas gathering system. 

Costs Capital, installation and startup cost estimates: $1,900-$7,800 (Note: Commenters on the ICF 

study cited a cost of $15,000. The study escalated the cost to $20,000 .Smart automation system: 

$4,700/well-$18,000/well depending on the complexity of the system. Additional startup costs 

(e.g., well depth survey, miscellaneous well clean out operations): $700-$2,600. 
23 

Efficacy and 

Prevalence

API/ANGA Survey data show plunger lifts can result in zero emissions or significant emissions 

depending on how they are operated. The EPA has learned plunger lift systems rely on manual, 

onsite adjustments. When a lift becomes overloaded, the well must be manually vented to the 

atmosphere to restart the plunger. Optimized plunger lift systems (e.g., with smart well 

automation) can decrease the amount of gas vented by up to 90+% and reduce the need for 

venting due to overloading. 

Approach Artificial Lift Systems ( including rod pumps, beam lift pumps, pumpjacks) 

Description Artificial lifts require an external power source to operate a pump that removes the liquid 

buildup from the well tubing. 

Applicability The devices are typically used during the eventual decline in the gas reservoir shut-in 

pressure, when there is inadequate pressure to use a plunger lift. At this point, the only 

means of liquids unloading to keep gas flowing is downhole pump technology. 

Costs Capital and installation costs (includes location preparation, well clean out, artificial lift 

equipment and pumping unit): $41,000-$62,000/well. Average cost of pumping unit: $17,000-

$27,000. 

Efficacy and 

Prevalence

Artificial lifts can be operated in a manner that produces no emissions. The EPA does not have 

information on the prevalence of this technology in the field. 

Approach Velocity Tubing 

Description Velocity tubing is smaller diameter production tubing and reduces the cross-sectional area of 

flow, increasing the flow velocity and achieving liquid removal without blowing emissions to 

the atmosphere. Generally, a gas flow velocity of 1,000 fpm is necessary to remove wellbore 

liquids. 

Applicability Velocity tubing strings are appropriate for low volume natural gas wells upon initial completion 

or near the end of their productive lives with relatively small liquid production and higher 

reservoir pressure. Candidate wells include marginal gas wells producing less than 60 Mcfd. 

Coil tubing can also be used in wells with lower velocity gas production. 

Costs Requires a well workover rig to remove the existing production tubing and place the smaller 

diameter tubing string in the well. Capital and installation costs provided from industry 

include: $7,000-$64,000/well. 

Efficacy and 

Prevalence

Considered to be a “no emissions” solution. Low maintenance, effective for low volumes lifted. 

Often deployed in combination with foaming agents. Seamed coiled tubing may provide better 

lift due to elimination of turbulence in the flow stream. The EPA does not have information on 

the prevalence of this technology in the field. 

Approach Foaming Agents 

Description A foaming agent (soap, surfactants) is injected in the casing/tubing annulus by a chemical 

pump on a timer basis. The gas bubbling through the soap-water solution creates gas-water 

foam which is more easily lifted to the surface for water removal. 

Applicability Application of mechanical controls is limited because the control must be located A 

means of power will be required to run the surface injection pump. The soap supply will 

also need to be monitored. If the well is still unable to unload fluid, additional, smaller 

tubing may be needed to help lift the fluids. Foaming agents work best if the fluid in the 

well is at least 50% water. Surfactants are not effective for natural gas liquids or liquid 

hydrocarbons. Foaming agents and velocity tubing may be more effective when used in 

combination. 

Costs Foaming agents are low cost. No equipment is required in shallow wells. In deep wells, a 

surfactant injection system requires the installation of surface equipment and regular 

monitoring. Pump can be powered by solar or AC power or actuated by movement of another 

piece of equipment. Capital and startup costs to install soap launchers: $500-$3,880. Capital and 

startup costs to install soap launchers and velocity tubing: $7,500-$67,880 Monthly cost of 

foaming agent: $500/well or $6,000/yr. 

Efficacy and 

Prevalence

Considered to be a “no emissions” solution. Low volume method applied early in production 

decline when bottom-hole pressure still generates sufficient velocity to lift liquid droplets. The 

EPA does not have information on the prevalence of this technology in the field. 
24 

6.4 Peer Review Opinion 

The primary peer review comments included: the white paper was not the complete, high quality 

technical resource document contemplated and is not suitable to inform deliberations; some summaries 

are incomplete, there are misstatements and misunderstandings scattered throughout the paper; the 

paper does not discuss the limitations of the underlying sources of information and no critical analysis 

of the accuracy or validity of the sources; the paper does not provide analysis of data, only a summary; 

the peer reviewer states that EPA has a fundamental misunderstanding of the process of venting to 

assist in liquids unloading, which causes emissions as well as options for emissions mitigation; the 

EPA has a misconception about plunger lifts. Installation or use of plunger lifts are a technique in the 

management of unloading of liquids from wells, however, use of PLs does not mean “venting” will be 

eliminated or reduced; the white paper was erroneous on interpretation of NGS limited data that 

plunger lifts are an emissions mitigation technique and API/ANGA does not support it; most of the 

emission factors taken from the summarized studies combine wells with and without plunger lifts. 

Separate factors should be developed; an average emission factor based solely on venting wells does 

not accurately characterize the effectiveness of this control technology for eliminating emissions from 

the majority of wells; and since the GHGRP only includes emissions from facilities above the 25,000 

MT CO2e reporting threshold, it should not be considered a comprehensive estimate of national 

emissions. The 2014 GHG Inventory estimate is lower than the total emissions reported to the 

GHGRP, so it also clearly underestimates national emissions. 
Small Business Advocacy Review Panel

Panel Outreach Meeting with Small Entity Representatives

Emission Standards for New and Modified Sources in the Oil and Natural Gas 

Sector

Thursday June 18, 2015 

EPA HQ, WJC North, room 4530 

2:00 pm – 5:00 pm (eastern) 

2:00 Welcome (EPA’s Small Business Advocacy Chair, Office of Policy (OP)) 

2:05 Introduction of Panel Members/Staff 

o EPA/Office of Air (OAR) 

o SBA/Office of Advocacy 

o OMB/Office of Information and Regulatory Affairs (OIRA) 

2:10 Introduction of SERs and Other Attendees (OP) 

2:20 Panel Process Questions? (OP takes questions from SERs) 

2:30 Panel Presentation (OAR) 

3:00 Discussion of the Rulemaking (SERs with Panel) 

o General Questions 

o Hydraulically Fractured Oil Well Completions 

o Fugitive Emissions 

o Pneumatic Pumps 

o Pneumatic Controllers 

o Compressors 

o Liquids Unloading 

o Reporting & Recordkeeping 

o Additional Input 

4:50 Next Steps and Closing (EPA/OP) 

o Comments due June 29, 2015 

********************************************** 

Teleconference dial-in number: (866) 299-3188 

Conference code: 202 564 1550 

Dial the toll-free teleconference number listed above. At the prompt, enter the conference code 

followed by the pound [#] sign. Note: You will hear music until the leader dials into the call.
Offic

Office of Regulatory P

http://w

A Refresher on the Small BusinAdvocacy Review Panel Proces

Alexander Cristofaro, Small Business Advocacy Review Chair 

Panel Outreach Meeting, June 18, 2015
Today’s Topics

• What is a Small Business Advocacy Review (SBA

Panel?

• Your role as a Small Entity Representative (SER)• The difference between an SBAR Panel and a pr

regulation
What is an SBAR Panel?

• A Panel consists of representatives from the: 

 Agency authoring the regulation (i.e., EPA) OMB’s Office of Information and Regulatory Affairs (O

 SBA’s Office of Advocacy

• The Regulatory Flexibility Act (RFA) instructs the 

to:

 Review “any material the agency has prepared” relate

development of the regulation

 Collect advice and recommendations from SERs Prepare a report within 60 days of the Panel convenin

See Title 5, section 609(b)(3)-(5), of the United States Code (USC). This is also known as section 60

Regulatory Flexibility Act (RFA).
What is an SBAR Panel? (con

• The types of materials the Panel will review and on which you, t

will provide advice and recommendations are specified by law

• Section 609(b)(4) of the RFA states that “the panel shall review 

material the agency has prepared...on issues related to”:

 “a description of and, where feasible, an estimate of the number of 

to which the proposed rule will apply” (Sec. 603(b)(3))

 “a description of the projected reporting, recordkeeping and other c

requirements of the proposed rule, including an estimate of the clasentities which will be subject to the requirement and the type of proskills necessary for preparation of the report or record” (Sec. 603(b

 “an identification, to the extent practicable, of all relevant Federal r

may duplicate, overlap or conflict with the proposed rule” (Sec. 603

 “a description of any significant alternatives to the proposed rule w

accomplish the stated objective of applicable statutes and which misignificant economic impact ...on small entities” (Sec. 603(c))
Your role as a SER

• EPA values this SBAR Panel process because it provides u

important small entity perspectives and information

• Your verbal and written input is considered and valued by 

as the Panel develops the Panel report

• Copies of your written comments will be appended to the 

Report and a chapter in the Panel report will summarize t

• The Panel will consider the comments you provide to us, 

findings that ultimately appear in the report are those of tmembers: EPA, OMB, and SBA

• The Administrator will carefully consider the input we gat

the SERs and the Panel members, but is not legally bound the recommendations of the Panel
The difference between an SBAR P

and a proposed regulation

• SBAR Panel

 Reviews materials related to:

• the impacts of the regulation on small entities• Federal rules which may intersect with this proposed reg• Alternatives to the regulation that may minimize small e

impacts

 EPA uses the Panel report to inform our decision-maki

the forthcoming proposed regulation

• Proposed regulation

 Fully formed regulatory proposal or set of regulatory a

 You will have an opportunity to comment on the prop

like any other public citizen
Thank You

• Participation is voluntary and we appreciate the 

energy you put towards this rulemaking.

• Thank you - we know it is, and has been, an int

resource commitment.

• Contact my staff:

 Nicole Owens

EPA Office of Policy

owens.nicole@epa.gov
Panel Outreach Briefing: Emis

Standards for New and Modi

Sources in the Oil and Natura

Sector

June 2015
Deliberative - Do Not Cite or Quote 

Overview

► White House Announcement► Oil and Gas Sector Description► Coverage Under the 2012 NSPS► Hydraulically Fractured Oil Well Completions► Fugitive Emissions► Pneumatic Pumps► Pneumatic Controllers► Compressors► Liquids Unloading► Reporting & Recordkeeping ► Number of Potentially Affected Sources► Emissions Reductions from Potential Control Options ► Next Steps
Deliberative - Do Not Cite or Quote 

Oil and Gas Sector Description

Leaks from unprotected steel mains and service lines

Well completions

Oil Production

Storage tanks

Compressors

Pneumatic controllers

Well completions

Natural Gas Production & 

Venting of gas for maintenance or repair 

of pipelines or compressors

Leaks from compressor stations 

Gas Transmission

Leaks at metering and regulating stations

Gas Distribution

Pipeline blowdowns

Processing plant leaks 

Covered in Oil and Gas White Papers

Liq

Fu

Produced Water Evaporation Ponds

Gas pla

Compressors

Pneumatic Controllers

Fugitive Emissions

Pneumatic controllers

Pneumatic 

pumps

Pn
Deliberative - Do Not Cite or Quote 

Oil and Gas Sector – Current Regulatory Covera

Leaks from unprotected steel mains and service lines

Well completions

Oil Production

Storage tanks

Compressors

Pneumatic controllers

Well completions

Natural Gas Production & 

Venting of gas for maintenance or repair 

of pipelines or compressors

Leaks from compressor stations 

Gas Transmission

Leaks at metering and regulating stations

Gas Distribution

Pipeline blowdowns

Processing plant leaks 

Liq

Fu

Produced Water Evaporation Ponds

Gas pla

Compressors

Pneumatic Controllers

Fugitive Emissions

Pneumatic controllers

Pneumatic 

pumps

Pn

New and Existing Sources CoveredOnly New Sources CoveredCovered in White Papers 
Deliberative - Do Not Cite or Quote 

White House Announcement 

► On January 14, 2015, the White House announced 

forward on oil and gas; including:

► Regulatory approaches (NSPS)► Guidance to the States (CTG)► Voluntary programs (Expanded Natural Gas STAR) 

► NSPS Improvements

► Reduce emissions of GHGs and VOCs, and add equ

and processes to those source types currently coverNSPS standards – note: the controls for GHG and VOemission reductions are the same. 

► Specifically look at sources from the Oil and Gas Wh

Papers

• Hydraulically Fractured Oil Well Completions,• Fugitive Emissions,• Pneumatic Devices,• Compressors, and• Liquids Unloading.
Deliberative - Do Not Cite or Quote 

Coverage of white paper sources under 2012 N

► Well Completions (hydraulically fractured gas wells► Equipment Leaks (at natural gas processing plants► Pneumatic Controllers (through gas processing)► Compressors (through gas processing, excluding w

compressors) 

► Liquids Unloading (not addressed in 2012 NSPS)
Deliberative - Do Not Cite or Quote 

► Not covered in 2012 NSPS► Control Options

► Reduced Emission Completions► Combustion

► Pre-panel SER written comments

► Exempt low producing wells ► Exempt low pressure wells► Exempt low gas-to-oil ratio (GOR) wells

► Input requested from SERs

► Appropriate production threshold (e.g. stripper well - 15 

per day – 22% of wells)

► Appropriate pressure threshold- are there particular 

considerations for oil wells?

► Is the use of GOR an appropriate approach for establis

threshold (e.g., 300 or 500 scf gas per barrel, 24% and wells respectively)?

Hydraulically Fractured Oil Well Completions

OilGas

W
Deliberative - Do Not Cite or Quote 

Hydraulically Fractured Oil Well Completions – Control Optio

W

Option Description Applicability/Effectiveness Esti

Reduced Emission Completions

“Green” or “flareless” completions, use specially designed equipment at the well site to capture and treat gas so it can be directed to the sales line. Additional equipment required to conduct a REC may include additional tankage, special gas-liquid-sand separator traps, and a gas dehydrator. Portable equipment used for RECs can operate in tandem with the permanent equipment that will remain after well drilling is completed.

Some limitations exist for performing RECs since technical barriers fluctuate from well to well: proximity of pipelines, pressure of produced gas, and inert gas concentration. Emissions reductions will vary according to reservoir characteristics and other parameters. Any amount of gas that cannot be recovered can be directed to a completion combustion device in order to achieve a minimum 95 percent reduction in emissions.

Equipmewith RECwell. A Restimate$10,000 complet

Combustion Completion combustion is a hightemperature oxidation process used to 

burn combustible components, mostly hydrocarbons, found in waste streams. 

Combustion devices are rather crude and portable, often installed horizontally due to the liquids that accompany the flowback gas. The flow directed to a completion combustion device may or may not be combustible depending on the inert gas composition of flowback gas, which would require a continuous ignition source. Combustion devices do not employ an actual control device, and are not capable of being tested or monitored for efficiency.

Combustannual cbetween $4,000 pcomplet
Deliberative - Do Not Cite or Quote 

► 2012 NSPS includes equipment leaks (at natural gas 

processing plants)

► Control Options

► Optical Gas Imaging – “Infrared Camera”► Method 21► Frequency of surveys (e.g., annual, semiannual, quarterly)

► Pre-panel SER written comments

► Concerned about overburdening small operators► Recommended against using Colorado Regulation 7 LDAR pr

model (We heard: burdensome with little environmental benefrequency of inspections and reporting too costly, lack of air qmodeling to quantify expected reductions, loss of marginal we

► Input requested from SERs

► Expand on issues with Colorado Regulation 7 implementation► Appropriate exemption threshold (e.g. 2.7 tons per year in PA

producing wells or stripper wells) 

► Feedback on appropriate flexibility or exclusions under certain 

circumstances

OilGas

W

Fugitive Emissions
Deliberative - Do Not Cite or Quote 

Fugitive Emissions – Control Options

Option Description Applicability/Effectiveness Estimated C

Optical Gas Imaging –“Infrared Camera”

OGI operates much like a consumer video-camcorder and provides a real-time visual image of hydrocarbon gas emissions or leaks to the atmosphere. The OGI camera works by using spectral wavelength filtering and an array of IR detectors to visualize the IR absorption of hydrocarbons and other gaseous compounds. As the gas absorbs radiant energy at the same waveband that the filter transmits to the detector, the gas and motion of the gas is imaged.

OGI instrument can be used for monitoring a large array of equipment and components at a facility, and is an effective means of detecting leaks when the technology is used appropriately. Information in the white paper related to the potential emission reductions from the implementation of an OGI monitoring program varied from 40 to 99 percent.

It is believed that the reduce the cost of ideemissions at oil and nwhen compared to usor OVA. The annual copads) ranges between OGI (gathering/boost$9,000 and $10,000; (transmission/storage$13,000 and $23,000Method 21 (well pads$1,500 and $3,000; M(gathering/boosting) $10,000 and $15,000(transmission/storage$7,000 and $25,000.

Frequency of Surveys The reduction of fugitive emissions 

involves the development of a fugitive emissions monitoring plan. An exemplary plan may incorporate semiannual survey.

The estimated annuafugitive emissions wilfrequency of the monactivities and type of 
Deliberative - Do Not Cite or Quote 

► Not covered in 2012 NSPS► Control Options

► Instrument (compressed) Air ► Switch to solar-powered or electric-powered► Route to a control device (e.g. combustion or vapor r

► Pre-panel SER written comments

► Gas processing plants have a very small number of 

pneumatic pumps, and provide little benefit in emissireductions from gas processing.

► Input requested from SERs

► What is the prevalence of control devices already at 

facilities?

► Are there site characteristics that make control devic

prevalent? (e.g. storage vessels) 

Pneumatic Pumps

OilGas

W
Deliberative - Do Not Cite or Quote 

Pneumatic Pumps – Control Options

Option Description Applicability/Effectiveness Es

Convert to Solar Pumps Solar power cells can generate electricity to 

power the pump. Solar cells can utilize a back-up power system to ensure reliability. 

Solar powered pumps are only reliable in areas where the sun can power the pump reliably. These devices, when applicable can result in 100 percent reduction in emissions where applicable.

Capital copumps is device

Covert to Electric Pumps Electric pumps can be used where a reliable 

source of electricity is available at the facility.

Electric powered pumps are only reliable with a constant supply of electricity. Overall, this option is applicable in niche areas but can achieve 100 percent reduction in emissions where applicable.

Capital coto $5,500 average a$260 per 

Convert to Instrument Air Instrument air systems can be used by 

replacing compressed air for the gas in pumps. These systems include a compressor, electrical power source, air dehydrator (depending on the type of pump), and volume tank. 

Instrument air systems reduce emissions by 100 percent by replacing natural gas with instrument air. This technology offers economies of scale, where it is more economical at facilities with more pneumatic pumps. The system requires a reliable source of electrical power. 

System coof comprelabor and Estimated between 

Route natural gas to an Existing Control Device

Routing natural gas from a gas-driven pump entails piping to a control device inlet stream.

Routing natural gas pumps to a combustion device reduces VOC and CH4 emissions by 95 percent. Routing natural gas to a control device is an option when a control device with available capacity is present on site. 

Costs will distance oannualize$200 and 

Route natural gas to Newly Installed Control Device

Routing natural gas from a gas-driven pump to a control device requires installation of a control device and piping between the pump and the control device. 

Routing natural gas-driven pumps to a combustion control device typically reduces VOC and CH4 emissions by 95 percent. 

Capital co$48,000 w$105,000

Route Natural Gas to Existing Gas Capture System

Routing natural gas from a gas-driven pump entails piping to a vapor recovery unit (VRU). 

Routing natural gas-driven pumps to a VRU reduces VOC and CH4 emissions through gas capture where emission reduction efficiencies are typically 95 percent. 

Capital cothe distanbut are esapproxim
Deliberative - Do Not Cite or Quote 

► 2012 NSPS covers pneumatic controllers in the 

production and processing segments

► Control Options

► Low bleed► Instrument (compressed) air► Mechanical or solar-powered systems► Enhanced maintenance

► Pre-panel SER written comments

► Instrument air systems are cost prohibitive for small g

processing operations 

► Input requested from SERs

► How many small entities own gas processing plants?► What is the prevalence of instrument air at gas proce

plants? 

Pneumatic Controllers

OilGas

W
Deliberative - Do Not Cite or Quote 

Pneumatic Controllers – Control Options

Option Description Applicability/Effectiveness 

Install Low Bleed Device in Place of High Bleed Device

Low-bleed devices provide the same functional control as a high-bleed device, while emitting lesscontinuous bleed emissions.

Applicability may depend on the function of instrumentation for an individual device on whether the device is a level, pressure, or temperature controller.

Convert to Instrument Air

Compressed air may be substituted for natural gas in pneumatic systems without altering any of the parts of the pneumatic control. In this type of system, atmospheric air is compressed, stored in a tank, filtered and then dried for instrument use. For utility purposes such as small pneumatic pumps, gas compressor motor starters, pneumatic tools and sand blasting, air would not need to be dried. Instrument air conversion requires additional equipment to properly compress and control the pressured air. This equipment includes a compressor, power source, air dehydrator and air storage vessel.

Replacing natural gas with instrument air in pneumatic controls eliminates VOC emissions from bleeding pneumatics. These systems can achieve 100 percent reduction in emissions. It is most effective at facilities where there are a high concentration of pneumatic control valves and an operator present. Since the systems are powered by electric compressors, they require a constant source of electrical power or a back- up natural gas pneumatic device. 

Mechanical and Solar Powered Systems in place of Bleed Device

Mechanical controls operate using a simple design comprised of levers, hand wheels, springs and flow channels. The most common mechanical control device is the liquid-level float to the drain valve position with mechanical linkages. Electricity or small electrical motors (including solar powered) have been used to operatevalves. Solar control systems are driven by solar power cells that actuate mechanical devices using electric power. As such, solar cells require some type of back-up power or storage to ensure reliability.

Application of mechanical controls is limited because the control must be located in close proximity to the process measurement. Mechanical systems are also incapable of handling larger flow fluctuations. Electric powered valves are only reliable with a constant supply of electricity. Overall, these options are applicable in niche areas but can achieve 100 percent reduction in emissions where applicable.
Deliberative - Do Not Cite or Quote 

► 2012 NSPS covers compressors in the gas production 

& processing segments; exempts well site compressors

► Control Options

► Reciprocating Compressors 

• Rod-Packing Replacement

► Centrifugal Compressors

• Dry Seals• Wet Seal with a Flare• Wet Seal with gas recovery

► Pre-panel SER written comments

► Upstream compressor controls are extremely burdenso

small operators

► Vapor recovery systems are cost prohibitive

► Input requested from SERs

► How would you characterize a “small” compressor?► Where are “small” compressors located and used? 

Compressors

OilGas
Deliberative - Do Not Cite or Quote 

Compressors – Control Options

Option Description Applicability/Effectiveness Est

Reciprocating Compressors- RodPacking Replacement

Over time the packing rings wear and allow more natural gas to escape around the piston rod. Regular replacement of these rings reduces CH4 and VOC emissions.

Piston rods, wear more slowly than packing rings, having a life of about 10 years. We assume operators will choose, at their discretion, when to replace the rod.

The estireplacembetwee

Centrifugal Compressors- Dry Seals

Centrifugal compressor dry seals operate mechanically under the opposing force created by hydrodynamic grooves and springs. 

Dry seals substantially reduce gas emissions compared to wet seals. At the same time, they significantly reduce operating costs and enhance compressor efficiency compared to wet seals.

The repwith dry savings $90,000

Centrifugal Compressors- Wet Seal with flare or gas recovery 

These seals use oil, which is circulated under high pressure between three rings around the compressor shaft, forming a barrier against the compressed gas leakage. The oil barrier allows some gas to escape from the seal, but considerably more gas is entrained and absorbed in the oil under the high pressures.

As a control measure, the recovered gas would then be sent to a combustion device or other process.

The annwith gas betwee
Deliberative - Do Not Cite or Quote 

► Not covered in 2012 NSPS► Control Options

► Route Emissions to Flare► Plunger Lift Systems► Artificial Lift Systems► Velocity Tubing► Foaming Agents 

► Cost is highly variable based on well characteristics► Pre-panel SER written comments

► Noted complexity of well liquid unloading► Regulatory uncertainty

► Input requested from SERs

► During a blowdown, is it feasible for emissions to be rou

flare?

► What are the techniques you currently use?► Do you have an estimated number of potentially affecte

sources?

Liquids Unloading

OilGas

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Deliberative - Do Not Cite or Quote 

► Options

► Retain 2012 REC-PIX alternative ► Electronic reporting

► Pre-panel SER written comments

► Limitation of small number staff ► High cost and difficulty of obtaining third-party contra► Concerned with duplicative efforts

► Input requested from SERs

► Please share other ideas to help streamline potentia

duplications.

► Are you familiar with the REC-PIX alternative to well 

completion reporting in the current NSPS (2012)?

► Do you find the provision for well completion notificat

helpful in reducing duplicative reporting (notification ustate or local requirement satisfies the NSPS)?

Reporting & Recordkeeping 
Deliberative - Do Not Cite or Quote 

Number of Potentially Affected Sources

Emissions Source No. Of Potentially Affec

New Sources Annual

Oil Well Completions 10,000 to 20,000Fugitive Emissions 15,000 to 25,000Pneumatic Pumps 2000 to 3000Compressors 50 to 100Pneumatic Controllers 200 to 300Liquids Unloading unknown
Deliberative - Do Not Cite or Quote 

Unit Reductions and Costs from Potential Control Opt

Emissions Source Control Options

Baseline Emissions (tons per year) Emission Reduction (tons per year) Na

P

R

(M

Methane VOC Methane VOC 

Oil Well Completions Reduced Emission 

Completion 9-10 8-9 9-10 7-8 8

Combustion 9-10 8-9 9-10 7-8 

Fugitive Emissions -Well Pads OGI 1-5 0-2 0-4 0-2 Fugitive Emissions -Gathering/Boosting Stations

OGI 30-40 9-10 10-35 3-8 1,1

Fugitive Emissions -Transmission and Storage Compressor Stations

OGI 60-170 1-5 20-140 0-4 1,5

Pneumatic Pumps –Production and Processing 

Route Emissions to 

Existing Control Device 0-4 0-1 0-4 0-1 

Instrument Air 0-4 0-1 0-4 0-1 

Pneumatic Pumps –Transmission and Storage

Route Emissions to 

Existing Control Device 0-4 0-1 0-4 0-1 

Instrument Air 0-4 0-1 0-4 0-1 

Compressors 

Rod Packing 

Replacement 25-35 0-1 20-30 0-1 1,0

Replace Wet Seals with 

Dry 100-160 3-5 100-140 3-5 5,0

Wet Seal with Gas 

Recovery 100-160 3-5 100-160 3-5 5,0

Route Emissions to 

Control 100-160 3-5 100-150 3-5 

Pneumatic Controllers

Install Low- or No-bleed 

Controllers 3-4 0-1 2-4 0-1 1

Instrument Air 3-4 0-1 3-4 0-1 1
Deliberative - Do Not Cite or Quote 

Additional SER Input Requested 

The Regulatory Flexibility Act (RFA) statute directs the Panel to collecrecommendations from SERs on issues related to:

► 603(b)(3) a description of and, where feasible, an estimate of the 

small entities to which the proposed rule will apply;

► 603(b)(4) a description of the projected reporting, recordkeeping a

compliance requirements of the proposed rule, including an estimaclasses of small entities which will be subject to the requirement aof professional skills necessary for preparation of the report or rec

► 603(b)(5) an identification, to the extent practicable, of all relevant 

which may duplicate, overlap or conflict with the proposed rule

► 603(c) each initial regulatory flexibility analysis shall also contain a 

of any significant alternatives to the proposed rule which accompliobjectives of applicable statutes and which minimize any significaimpact of the proposed rule on small entities; consistent with the sobjectives of applicable statutes, the analysis shall discuss significalternatives such as:

► The establishment of differing compliance or reporting requiremen

timetables that take into account the resources available to small 

► The clarification, consolidation, or simplification of compliance and 

requirements under the rule for such small entities;

► The use of performance rather than design standards; and► An exemption from coverage of the rule, or any part thereof, for su

entities
Deliberative - Do Not Cite or Quote 

Next Steps

► In addition to comments we heard today, written co

will be accepted by the panel (EPA, OMB, and SBAJune 29, 2015.

► Final report of this panel process will be developed 

July timeframe

► Proposal of the NSPS planned for summer 2015
Panel Outreach Briefing 

Emission Standards for New and Modified Sources in the Oil and Natural Gas Sector 

Supplemental Information 

Analysis Assumptions: 

• Control technologies with both capital and operating costs are annualized over the 

assumed technology life using a 7% interest rate. 

• Cost analysis are based on model facilities and typical costs. 

Oil Well Completions: 

• Activity data 

o Baseline completions count based on HPDI dataset for 2012. Classification of oil 

wells based on gas-to-oil ratio (GOR). 

o Projection of change in completions from 2012 through analysis years based on 

projections in AEO14/NEMS. 

o Classification of development versus delineation/exploration wells based on 

AEO14/NEMS. 

• Emissions 

o Emissions per day based on gas production in the first month from HPDI. 

o Assumption of 3 days per oil well completion based on white papers. 

o Reduction rate of 95% for combination of REC and flare based on white papers. 

o Assumption that RECs will be feasible for 50% of oil well completions (whereas 

for the remainder RECs will likely be infeasible for some combination of 

unavailability of infrastructure or other technical considerations). 

• Costs 

o Costs per day for REC equipment based on white paper and 2012 NSPS 

supplemental TSD, adjusted for inflation. 

o Costs per completion combustion device based on 2012 NSPS Supplemental 

TSD, adjusted for inflation. 

Fugitive Emissions: 

• Activity data 

o Baseline well pad counts based on HPDI dataset for 2012. 

o Assumed 2 wells per pad based on geographic analysis of HPDI dataset for 2012. 

o Projected change in wellpads from base year to projection years based on 

AEO14/NEMS. 

o Typical new compressor stations per year based on historical average of increases 

in the number of compressor stations in the 2012 U.S. GHG Inventory (published 

April 2014). 

o Equipment and component counts per gas well and compressor station based on 

GRI/EPA, which underlies the U.S. GHG Inventory for this source. Equipment 

and component counts for oil wells based on GHG Inventory. 
• Emissions 

o Emissions factors per component based on AP-42. 

o Reduction percentages based on expert judgement and the range of emissions 

reductions from the white paper. 

• Costs 

o Costs for OGI surveys based on white papers and comparison to other analyses 

such as Carbon Limits and Colorado rule analysis. Costs for repairs, overhead, 

planning, and program support based on per-hour estimates and typical labor 

rates. 

Pneumatic Pumps: 

• Activity data 

o Typical new pneumatic pumps per year based on historical average of increases in 

number of pumps per year from the U.S. GHG Inventory. 

o Consideration of two pump types/sizes (diaphragm/heat-trace and piston/plunger 

pump). 

o Pumps primarily analyzed at well sites. 

o Consideration of pumps located at sites where controls are already present (e.g., 

for a storage vessel or wet seal compressor) versus pumps located at sites without 

existing controls. 

• Emissions 

o Reduction percentage of 95% based on white papers. 

• Costs 

o Costs for control devices and piping based on typical cost assumptions. 

Pneumatic Controllers: 

• Activity data 

o Typical new high-bleed pneumatic controllers based on historical average of 

increases in number such controllers in the U.S. GHG Inventory. 

o Assumption that a portion of high-bleed pneumatic controllers are needed for 

operational reasons and cannot be replaced with low-bleed controllers. 

• Emissions 

o Emissions per controller based on white paper and 2012 NSPS analysis. 

• Costs 

o Costs based on incremental cost difference between a low-bleed and high-bleed 

pneumatic controller, from white paper and 2012 NSPS analysis. 

Compressors: 

• Activity data 

o Typical new wet seal compressors and reciprocating compressors in transmission 

and storage based on historical average of increases in number of such controllers 

in the U.S. GHG Inventory. 
• Emissions 

o Emissions per compressor based on white paper and 2012 NSPS analysis. 

• Costs 

o Costs based on white paper and 2012 NSPS analysis. 
Panel Outreach Briefing (Update 6/26/2015) 

Emission Standards for New and Modified Sources in the Oil and Natural Gas Sector 

Supplemental Information – Slide 20 Data and Assumptions 

Oil Well Completions 

Emissions Source Control Options

Baseline Emissions (tons per 

year)

Emission Reduction (tons per 

year)

Natural Gas 

Product 

Recovery 

(Mcf/year)

Annualized Cost 

with Savings 

(2012$) Methane VOC Methane VOC

Oil Well 

Completions 

Reduced Emission 

Completion 9-10 8-9 9-10 7-8 

800-900 $10,000-$15,000 

Combustion1 9-10 8-9 9-10 7-8 0 $3,000-$4,000 

Baseline Emissions 

 Based on 3-day completion or recompletion event. 

 The average daily production of natural gas was estimated using data on gas production from oil wells (with gas to oil 

ratio of 300-100,000)2

 in the DrillingInfo database for CY 2012. We used the average daily production from the first 

month of production. This average daily production was then multiplied by 3 for the average production from a 3-day 

completion event. 

 Potential Emissions: CH4 9.72 tons/event and VOC 8.14 tons/event. Calculated from natural gas production per event. It is 

assumed CH4 comprises 46.732 percent by volume of natural gas. (Factors: 0.0208 tons CH4 per Mcf and 0.8374 lb. 

VOC/lb. CH4)

3

 

Emission Reductions 

 Reduced Emission Completions 

 Assumes 90 percent of flowback gas can be recovered during a REC 

 Memorandum to Bruce Moore, U.S. EPA from ICF Consulting. Percent of Emissions Recovered by 

Reduced Emission Completions. May 2011. 

 Any amount of gas that cannot be recovered can be directed to a completion combustion device in order to 

achieve a minimum 95 percent reduction in emissions. 

 95 percent recovery was estimated based on 90 percent of flowback being captured to the sales line and

assuming an additional 5 percent of the remaining flowback would be sent to the combustion device. 

(2011 TSD, p 4-28) 

 Combustion 

 Assumes destruction efficiency of 95 percent, consistent with the expected destruction efficiency of a properly 

designed and operated flare for completion combustion devices over the duration of the completion or 

recompletion. (2011 TSD, p. 4-19) 

Cost 

 Reduced Emission Completion 

 The annual cost of performing a REC was estimated to be $12,735 ($13,459 in 2012$) for a representative well 

completion lasting 3 days. 2011 TSD, page 4-16. 

 

1

 Consistent with the 2012 NSPS, EPA is considering a tiered approach for reducing emissions from oil well completions. For 

example, REC will be required where feasible, and combustion where an REC is not feasible. 

2

 EPA is only considering regulating hydraulically fractured or refractured oil wells with gas oil ratios greater than 300. 

3

 Memorandum to Bruce Moore, U.S. EPA from Heather Brown, EC/R. "Composition of Natural Gas for use in the Oil and Natural 

gas Sector Rulemaking". July 2011. Docket ID EPA-HQ-OAR-2010-0505-0084. 
 Assumes the cost to rent equipment to perform a REC for an oil well completion costs the same per day as the 

cost analysis for gas well completions. 

 Combustion 

 Estimated average completion combustion device cost of approximately $3,523 (2008 dollars) (2011 TSD, pp. 4-

19 to 4-20) 

Fugitive Emissions 

Emissions Source Control Options

Baseline Emissions (tons per 

year)

Emission Reduction (tons per 

year)

Natural Gas 

Product 

Recovery 

(Mcf/year)

Annualized Cost 

with Savings 

(2012$) Methane VOC Methane VOC

Fugitive Emissions - 

Well Pads OGI 1-5 0-2 0-4 0-2 30-160 $1,500-$2,000 

Fugitive Emissions - 

Gathering/Boosting 

Stations 

OGI 30-40 9-10 10-35 3-8 1,100-1,300 $9,000-$10,000 

Fugitive Emissions - 

Transmission and 

Storage Compressor 

Stations 

OGI 60-170 1-5 20-140 0-4 1,500-5,500 $13,000-$23,000 

Baseline Emissions 

 Equipment and component counts per gas well and compressor station based on GRI/EPA, which underlies the U.S. 

GHG Inventory for this source. Equipment and component counts for oil wells based on GHG Inventory. Gas 

Research Institute (GRI)/U.S. EPA. Research and Development, Methane Emissions from the Natural Gas Industry, 

Volume 8: Equipment Leaks. June 1996 (EPA-600/R-96-080h). 

http://www.epa.gov/gasstar/documents/emissions_report/8_equipmentleaks.pdf

Emission Reduction 

 Emissions factors per component based on AP-42. 

 U.S. EPA, Protocol for Equipment Leak Emission Estimates, Table 2-4, November 1995. (EPA-453/R-95-017)

http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf

 Emission reductions from the implementation of an OGI monitoring program varied from 40 to 80 percent 

(assumptions: 40% - annual inspections; 60% - semiannual inspections; 80% - quarterly monitoring). 

 Ranges account for the varying efficacies of quarterly, semiannual, and annual monitoring. 

Costs 

 Costs for OGI surveys based on white papers and comparison to other analyses such as Carbon Limits and Colorado 

rule analysis. Costs for repairs, overhead, planning, and program support based on per-hour estimates and typical 

labor rates. 

 Colorado Air Quality Control Commission, Initial Economic Impact Analysis for Proposed Revisions to 

Regulation Number 7 (5 CCR 1001-9). November 15, 2013. 

https://www.colorado.gov/pacific/sites/default/files/062_R7-Initial-EIA-request-11-21-13-26-pgs-062_1.pdf

 Carbon Limits. Quantifying cost-effectiveness of systematic LDAR Programs using IR cameras. December 24, 

2013. http://www.catf.us/resources/publications/files/CATF-Carbon_Limits_Leaks_Interim_Report.pdf

 Labor rate: $57.80/hour. Source: Table 11 of the Uniform Standards memo - Memorandum to Jodi Howard, 

EPA/OAQPS from Cindy Hancy, RTI International, Analysis of Emission Reductions Techniques for Equipment 

Leaks, December 21, 2011. 
Pneumatic Pumps 

Emissions Source Control Options

Baseline Emissions (tons per 

year)

Emission Reduction (tons per 

year)

Natural Gas 

Product 

Recovery 

(Mcf/year)

Annualized Cost 

with Savings 

(2012$) Methane VOC Methane VOC

Pneumatic Pumps – 

Production and 

Processing 

Route Emissions to 

Existing Control 

Device 

0-4 0-1 0-4 0-1 0 $200-$300 

Instrument Air 0-4 0-1 0-4 0-1 0 $800-$8,000 

Pneumatic Pumps – 

Transmission and 

Storage 

Route Emissions to 

Existing Control 

Device 

0-4 0-1 0-4 0-1 0 $200-$300 

Instrument Air 0-4 0-1 0-4 0-1 0 $800-$8,000 

Baseline Emissions 

 Ranges primarily based on differences between piston and diaphragm pumps 

 Piston Pumps: Methane emissions range from 0-0.5 tpy; VOC from 0-0.25 tpy; varying based on location 

 Diaphragm Pumps: Methane emissions range from 3-4 tpy; VOC from 0.5-1 tpy; varying based on location 

 Data Sources: EPA/GRI. Methane Emissions from the Natural Gas Industry, Volume 13: Chemical Injection Pumps. 

June 1996 (EPA-600/R -96-080m), Sections 5.1 – Diaphragm Pumps and 5.2 – Piston Pumps 

Emission Reductions 

 Route to Control - Capture systems combined with combustion devices are considered a reliable mechanism to 

reduce approximately 95 percent of emissions (2011, TSD, p. 6-23) 

 Instrument Air - Reductions over 95% (U.S. EPA. PRO Fact Sheet No. 202. Convert Natural Gas-Driven Chemical 

Pumps.) 

Costs 

 Route to Control 

 Capital cost for installing a new combustion device is $34,250 and the annual operating costs are $17,001 in 

2012 dollars. In the 2012 supplemental TSD, the combustor cost was estimated to be $32,301 in 2008 

dollars (see Table 7-5, p. 7-6). This was escalated to $34,250 in 2012 dollars. 

 Instrument Air 

 Replacing Gas-Driven Pumps with Instrument Air System – annualized cost: Small plants – $10,000 to 

$15,000; Medium plants - $30,000 to $40,000; Large plants -$70,000 to $80,000 

 Based on model plants with 4, 10, 20, 50, and 100 pumps, with varying distribution scenarios between 

diaphragm and piston pumps (ie, 50/50;75/25; 25/75) 

 The compressor costs used in our analysis were drawn from the costing analysis conducted for the 2011 

NSPS proposal for instrument air systems for pneumatic controllers (2011 TSD, Table 5-10, p. 5-21.) 

 We estimate that each diaphragm pump replaced will save 197 Mcf per year of natural gas from being 

emitted and each piston pump will save of 22 Mcf per year. The value of the natural gas saved based on

$4.00 per Mcf would be $786 per year per diaphragm pumps and $87 per year per piston pump. 

 The natural gas emission factor for a diaphragm to be 22.45 scf/hr. Thus, (22.45 scf/hr x 8760 

hrs/yr)/1000 = 197 Mcf/yr. Cost savings: 197 Mcf x $4/Mcf = $786 

 The natural gas emission factor for a piston pump to be 2.48 scf/hr. Thus, (2.48 scf/hr x 8760 hr/yr)/1000 = 

22 Mcf/yr. Cost savings: 22 Mcf x $4/Mcf = $87 
 EPA/GRI. Methane Emissions from the Natural Gas Industry, Volume 13: Chemical Injection Pumps. June 

1996 (EPA-600/R -96-080m), Sections 5.1 – Diaphragm Pumps and 5.2 – Piston Pumps. 

Compressors 

Control Options

Baseline Emissions (tons per year) Emission Reduction (tons per year) Natural Gas 

Product 

Recovery 

(Mcf/year)

Annualized Cost 

with Savings (2012$) Methane VOC Methane VOC

Rod Packing Replacement 25-35 0-1 20-30 0-1 1,000-1,200 $1,700-$2,100 

Replace Wet Seals with 

Dry 

100-160 3-5 100-140 3-5 5,000-6,000 

($80,000) to 

($90,000) 

Wet Seal with Gas 

Recovery 

100-160 3-5 100-160 3-5 5,000-6,000 $3,000-$5,000 

Route Emissions to Control 100-160 3-5 100-150 3-5 0 $110,000-$120,000 

Baseline Emissions 

 Reciprocating - The methodology for estimating emission from reciprocating compressor rod packing was to use the 

CH4 emission factors referenced in the EPA/GRI study

4

 and the CH4-to-VOC ratio developed in the gas composition 

memorandum. 

 Centrifugal - The compressor emission factors for wet seals and dry seals are based on data used in the GHG 

Inventory5. The wet seals CH4 emission factor was calculated based on a sampling of 48 wet seal centrifugal 

compressors. The dry seal CH4 emission factor was based on data collected by the Natural Gas STAR Program. 

Emission Reductions 

 Reciprocating 

 The emission reductions for the transmission and storage segments were calculated by multiplying the 

number of new reciprocating compressors in each segment by the difference between the average rod 

packing emission factors and the average emission factor for newly installed rod packing. 

 Centrifugal 

 Dry seals - The dry seal emission factor is based on information from the Natural Gas STAR Program.6

 Route to Control - A combustion device typically achieves 95 percent reduction of these compounds when

operated according to the manufacturer instructions (2011 TSD p. 6-23) 

Cost 

 Reciprocating 

 Replacement of the packing rings to be $1,712 per cylinder 

 http://www.epa.gov/gasstar/documents/ll_rodpack.pdf. Average cost in NGSTAR data was $1,620 

which was converted to 2012 dollars for our assessment. 

 On average, each reciprocating compressor has 3.3 cylinders. 

 Replace every three years, during planned shutdowns and maintenance 

 

4

 National Risk Management Research Laboratory. GRI/EPA Research and Development, Methane Emissions from the Natural Gas 

Industry, Volume 8: Equipment Leaks. Prepared for the U.S. Department of Energy, Energy Information Administration. EPA-600/R96-080h. June 1996. 

5 U.S. EPA. Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. GHG Inventory: Emission and Sinks: 

1990-2012. Washington, DC. 2014.

6

 U.S. EPA. Lessons Learned: Replacing Wet Seals with Dry Seals in Centrifugal Compressors. Natural Gas STAR. 2006. 
 Centrifugal 

 Dry seals - Annual operation and maintenance savings from the installation of dry seal compressor is 

$88,300 in comparison to wet seal compressor. 

 http://www.epa.gov/gasstar/documents/ll_wetseals.pdf. See p. 4, Exhibit 4. 

 Route to Control - The capital and annual cost of the combustion device was calculated using the 

methodology in the EPA Control Cost Manual.7

Controllers 

Emissions Source Control Options

Baseline Emissions (tons per 

year)

Emission Reduction (tons per 

year)

Natural Gas 

Product 

Recovery 

(Mcf/year)

Annualized 

Cost with 

Savings (2012$) Methane VOC Methane VOC

Pneumatic 

Controllers 

Install Low- or Nobleed Controllers 3-4 0-1 2-4 0-1 140-150 $20-$30 

Instrument Air 3-4 0-1 3-4 0-1 140-150 $2,000-$20,000

Baseline Emissions 

 Low-bleed devices on the market today have emissions from 0.2 scfh up to 5 scfh and high-bleed devices vary 

significantly from venting as low as 7 scfh to as high as 100 scfh. 

 U.S. EPA. GHG Emissions Reporting From the Petroleum and Natural Gas Industry: Background TSD. Climate

Change Division. Washington, DC. November 2010. 

 EPA determined that best available emissions estimates for pneumatic controllers are presented in Table W-3 of 

the GHG Mandatory Reporting Rule for the Oil and Natural Gas Industry (Subpart W) 

 http://www.gpo.gov/fdsys/pkg/CFR-2012-title40-vol22/pdf/CFR-2012-title40-vol22-sec98-238-appW.pdf

Reductions 

 Low Bleed 

 95% reduction from low-bleed devices - calculated from GHGRP data considering the difference between 

the emissions of a high-bleed and low-bleed device.

 Table W-1A of the GHG Mandatory Reporting Rule for the Oil and Natural Gas Industry (Subpart W) 

 Instrument Air 

 These systems can achieve 100 percent reduction in emissions.

Costs 

 Low Bleed 

 The average cost for a high bleed pneumatic is $2,471, while the average cost for a low bleed is $2,698.

incremental cost of installing a low-bleed device instead of a high-bleed device is ~$227 per device 

 2011 TSD, Table 5-7, p. 5-15. The values from this table were escalated to 2012 dollars. 

 Incremental cost to install a low-bleed instead of a high-bleed was annualized for a 15-year period using a 7 

percent interest rate. This equated to an annualized cost of around $25 per low-bleed controller. 

 2012 NSPS major pneumatic controller vendors were surveyed for costs, emission rates, and any other 

pertinent information that would give an accurate picture of the present industry (2011 TSD, p. 5-15).

 Instrument Air 

 

7

 EPA Air Pollution Control Cost Manual - Sixth Edition, (EPA 452/B-02-001). 
 System costs are dependent on size of compressor, power supply needs, labor and other equipment.8

Overall Assumptions and Links 

 Unless otherwise specified, all costs are 2012$ 

 2011 TSD: U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude 

Oil and Natural Gas Production, Transmission, and Distribution. Background Technical Support Document for 

Proposed Standards. July 2011. EPA-453/R-11002. http://www.epa.gov/airquality/oilandgas/pdfs/20110728tsd.pdf 

 2012 TSD: U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude 

Oil and Natural Gas Production, Transmission, and Distribution. Background Supplemental Technical Support 

Document for Proposed Standards. April 2012. Docket ID EPA-HQ-OAR-2010-0505-4550. 

http://www.epa.gov/airquality/oilandgas/pdfs/20120418tsd.pdf 

 

8

 2011 TSD discusses the costs of instrument air requirements for gas processing plants, which may be considered an analogous 

requirement here.