## 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 1 9 , 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 O MB/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)

1:5 0 Discussion of the Rulemaking (SERs with Panel)

2:50 Summary and Closing (EPA/OP)

********************************************** Teleconference dial

- in number: (866) 299

- 3188 Conference code: 202 56 4 1550 Dial the toll

- free teleconference number list ed 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.)



# • SBREFA 1 

# 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 decision



# making 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 2015Deliberative

- 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

2Deliberative

- 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 pumpsDeliberative

- 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 CO2eDeliberative

- 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

5Deliberative

- 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

► 

# R educe 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

6Deliberative

- 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 7Deliberative

- 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 f rom 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):

► 

### D etection technologies

► 

### F requency 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 

### 8Deliberative

- Do Not Cite or Quote 

# Pneumatic Pumps

► 

## Emissions are vented when pneumatic pumps operate

► 

## Multiple types of pneumatic pumps

► 

### Chemical/methanol injection pumps



### • S mall and very common at well sites

► 

### Diaphragm pumps



### • Similar to chemical/methanol injection pumps but larger

► 

### Gas assist pumps (glycol pumps)



### • U sed 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 9Deliberative

- 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

10Deliberative

- 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 11Deliberative

- 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

12Deliberative

- 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

13Deliberative

- 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

14Deliberative

- 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 2016Potential Small Entity Representatives

- Emission Standards for New and Modified Sources in the Oil and Natural Gas Sector 1



### Name Affiliation Contact Information

Tom Murphy 2 

### 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 Americ a, 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 Kriebel 3


### 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
Assoc iation mruckel@toga.org
512

- 478

- 6631

Sarah Bartlett Lead Air Quality EHS
Professional PDC Energy, Inc. Colorado Sarah.Bartlett@PDCE.com
303

- 831

- 3969

3 

### Dave Ochs and Roy Rakiewicz will serve as Helpers.

# Oil and Natural Gas White Papers

Abridged Summary

Prepared for the Small Business Advocacy Review Pan el
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 pe er 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 e missions mitigation techniques from potentially significant sources of emissions in the oil and nat ural gas sector. Specifically, the white papers foc us 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 c ontent of the white papers and a high level overview of the comments submitted by the peer revi ewers.

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 th at 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 Completion s
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 L eaks
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 De vices
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 a nd control technologies completions and associated gas from ongoing production at hydraulic ally fractured oil wells. Hydraulic fracturing is o ne technique for improving oil and gas production wher e the reservoir rock is fractured with very high pressure fluid, typically a water emulsion with a p roppant (generally sand) that “props open” the fractures after fluid pressure is reduced. Completi on operations with hydraulic fracturing are conduct ed to either bring a new oil well into the production phase or to maintain or increase the well’s product ion capability (sometimes referred to as a recompletion ). Well completions with hydraulic fracturing inclu de multiple steps after the well bore hole has reached the target depth. These steps include inserting an d cementing-in well casing, perforating the casing at one or more producing horizons, and often hydraulically fracturing one or more zones in the r eservoir to stimulate production. Surface component s, including wellheads, pumps, dehydrators, separators , tanks, and are installed as necessary for product ion 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 e xcess proppant and fluids to the surface. This comingled fluid stream (containing produced oil, na tural gas and water) flows from each drilled well t o a respective vertical separator and heater/treater processing unit. Phase separation is the process of removing impurities from the hydrocarbon liquids an d 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 i s frequently sent to combustion devices for destruc tion (e.g., flares) or is vented to the atmosphere. Associated gas is the term typically used for natur al gas produced as a by-product of the production of crude oil. Industry publications typi cally refer to associated gas as gas that is coprod uced with crude oil while the well is in the production phase and is vented directly to the atmosphere or i s flared. Therefore, associated gas can include gas t hat 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 storag e vessels.

2.2 Emissions Data The white paper describes the processes used to est imate 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 est imated gas produced during completions, gas produced by the well over a certain production peri od, gas composition data from analysis of various g as streams, and data on duration of completion cycles. Various elements of these data are provided in various studies and information sources presented b elow.

Source of Data Fort Berthold Federal Implementation Plan, 2012

Emissions Source Description From 154 synthetic minor permit applications for oi l wellheads, heater/treaters and storage tanks, representing 533 production wells, f ive major operators Type of Data: Estimated VOC emissions from above sources, oil pro duction data, number of storage

### 4 tanks, combustors, flares and presence of a pipelin e, 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 emiss ions using gas composition and oil production data and emission factors for oi l wells from GRI/EPA study. Methane or VOC emission factors/ emissions findings No new emission factors developed. However, the stu dy of the data provided an opportunity to analyze production data and emission s information to determine potential completion emissions. Applicability to ONG Sector Although a large data set, data was regionally base d in two formations. Gas composition and production had high variability and also may di ffer 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 represen ting county level average daily natural gas production at 5,754 oil well completion s Emissions Estimation/ Measurement Using HPDI oil well data and GRI/EPA gas compositio n data, calculated methane and VOC emissions from 7 and 3 day completion durations . Using data from Colorado, Texas and Wyoming state reported data, calculated p ercentage 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 ton s 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 wel ls. Assumes no control applied. Nationwide level of use of RECs or combustors on oi l 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 Watt enberg 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 met hane content. Emissions Estimation/ Measurement Estimated uncontrolled demission from oil well comp letions for each formation

Methane or VOC emission factors/ emissions findings 10.5 tons of methane per completion event for Watte nberg, 19.8 tons of methane per completions event for Bakken and 27.2 tons of metha ne per completion event for Eagle Ford. Applicability to ONG Sector Re-evaluation of HDPI data indicating similar findi ngs as other analysis conducted by EPA, with the exception of formation specific focus

. Source of Data Measurements of Methane Emissions at Natural Gas Pr oduction Sites in the United States, 2013 Emissions Source Description Academic/industry study to measure emissions from s everal oil and natural gas production sources, including gas and oil well comp letions Type of Data: 6 oil wells - oil produced, gas produced, gas-to-oi l 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, calcula ted methane and VOC emissions, measured gas composition and calculated emission re duction percentage for controls

### 5 used. Assumed a gas to oil ratio of 12,500 scf/barr el to distinguish oil wells from gas wells. Methane or VOC emission factors/ emissions findings Average duration 72 hours or 3 days. Average uncont rolled methane was 213 tons and average controlled was 3.2 tons. One well controlle d 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 Syste ms, 2013
Emissions Source Description Hydraulically fractured oil wells drilled in 2010 o r 2011 in Eagle Ford, Bakken and Permian formations Type of Data: HPDI data: oil well counts, oil production, gas pro duction Emissions Estimation/ Measurement O'Sullivan method, peak gas production (normally wi thin 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 us ing 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 p roduction data. However, the dynamics of gas reduction over the life of oil production would nee d to be considered. The second approach be to use gas production data reported by the well for econom ic or regulatory reasons. However, the data would not provide insight as to what was capture/controll ed or vented. The two sources of data discussed for associated gas were the Greenhouse Gas Reporting Pr ogram and a North Dakota flaring study. Neither of those sources were noted as providing informatio n 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 refractur ing 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. Limitat ions include proximity of the wall to a gas

pipeline, sufficient volume and pressure of produce d 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 compl etion would cost $29,022. These costs do not consider gas savings. Efficacy and Prevalence Depends on well and reservoir characteristics, howe ver, per Natural Gas STAR study, the

efficiency is estimated at 90 percent emissions red uction. No significant data is available on the prevalence of the use of RECs for oil well completi ons. Approach Completion Combustion Devices Description High temperature oxidation of hydrocarbons in the g as 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 sou rce. Generally one combustion device

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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 appropriat e 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 remova l of fracking fluids from the well. All commenters indicated that a more diligent effort should be put into determining the duration of flowback, specifi c 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 w ells used in the EPA estimates is unsupported with data in the white paper. Reviewers reiterated the h igh variability of all parameters need to estimate emission from completions and the need to further s tudy and establish data that directly relates to th e operation. Reviewers pointed out that EPA has misco nstrued recompletion versus refracturing and that the latter is what they are actually addressing in the white paper. Most reviewers indicated that indu stry is currently controlling some emissions from comple tions and noted methods to more fully quantify those data. For the most part, industry reviewers b elieved the emissions estimates to be overstated an d the environmental and state reviewers noted that th ey were understated.


## 3.0 Fugitive Emissions (Leaks) 3.0 Oil and Natural Gas Sector Leaks (Fugitive Emis sions) 3.1 Description of Process: The emissions data and the mitigation techniques pr esented in the White Paper are applicable to natural gas fugitive emissions from natural gas pro duction, processing, transmission, and storage. Som e of these emissions estimates and mitigation techniq ues are also applicable to oil wells that co-produc e 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 na tural gas distribution system (i.e., upstream of th e city gate). This includes fugitive emissions from natura l gas well pads, oil wells that co-produce natural gas, gathering and boosting stations, gas processing pla nts, and transmission and storage infrastructure. Potential sources of fugitive emissions from these sites include agitator seals, compressors seals, connectors, pump diaphragms, flanges, hatches, inst ruments, meters, open-ended lines, pressure relief devices, pump seals, valves, and improperly control led 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 emissi ons in the White Paper was derived by reviewing the various approaches taken in the available literatur e. Fugitive emissions occur through many types of con nection 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 str esses on equipment may eventually cause them to leak. Fugitive emissions can also occur when connec tion points are not fitted properly, which causes leaks from points that are not in good contact. Oth er leaks can occur due to normal operation of equipment, which, over time, can cause seals and ga skets to wear. Weather conditions can also affect t he performance of seals and gaskets that are intended to prevent leaks. Lastly, fugitive emissions can oc cur from equipment that is not operating correctly, suc h as storage vessel thief hatches that are left ope n or separator dump valves that are stuck open.

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### 3.2 Emissions Data

Source of Data Protocol for Equipment Leak Estimates, 1995 Emissions Source Description Provides standard procedures for estimating TOC mas s emissions from leaks at refineries, marketing terminals, oil and gas production operati ons and SOCMI facilities. Type of Data: Correlation equations and emission factors were dev eloped from leak data collected for valves, pumps, compressors, pressure relief valves, connectors, flanges and open-ended lines. Development of emission factor and correlati on 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 produc tion facilities. Estimation/ Measurement Provides 4 approaches for estimating leak mass emis sions from these sites; average emission factor, screening range, EPA correlation and unit s pecific correlation approach. Methane or VOC emission factors/ emissions findings The emission factors and correlation equations prov ide 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 fa ctor approach could be used for estimating methane and VOC leak emissions. Source of Data GRI/EPA Methane Emissions from the Natural Gas Indu stry, Volume 8: Equipment Leaks, 1996 Emissions Source Description Provides an estimate of annual methane emissions fr om leaks from the natural gas production sector using component counts and methan e emission factors. Type of Data: Correlation equations and emission factors were dev eloped 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. GR I Hi-Flow used to determine emission factors for some offshore production sourc es. For onshore natural gas production, facilities were broken into eastern and western cat egories, 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 cu bic feet per year (MMscf/yr) of methane are emitted as leaks from 271,928 onshore natural g as 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, natura l 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 emiss ion sources across a range of industry sectors, as well as suppliers of certain GHGs and p roducts that would emit GHGs if released or combusted. Type of Data: Covers a subset of national emissions, as facilitie s 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 emis sions, 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 pop ulation emission factors. Facilities in the onshore gas processing and gas transmission segment s use counts of leaking components and leak emission factors. Methane or VOC emission factors/ emissions findings For the 2012 reporting year, reported methane emiss ions 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 compressio n were 15,868 MT. Applicability to ONG Sector The 2012 GHG data for Petroleum and Natural Gas Sys tems was collected under the GHGRP. Source of Data Inventory of U.S. Greenhouse Gas Emissions and Sink s: 1990-2012 (U.S. EPA, 2014) Source Description: Tracks total U.S. GHG emissions and removals by sou rce and by economic sector over a

time series, beginning with 1990. The GHG Inventory includes estimates of methane and CO 2 for natural gas and petroleum systems.

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Type of Data: Covers all equipment that process or transport natu ral 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 pipelin es, drilling and well completions, normal operations, condensate tank vents, well work overs, liquids unloading, vessel blowdowns, and process upsets. Estimation/ Measurement Emission factors from the GRI/EPA adapted in the 20 14 GHG Inventory for each of the NEMS regions based on-specific methane content in p roduced natural gas. Methane or VOC emission factors/ emissions findings Estimated 332,662 MT of potential methane leak emis sions from gas wells and field separation equipment from natural gas production ac tivities in 2012; 33,681 MT of potential methane emissions from gas processing leak emission s and 114,348 MT of potential methane emissions from gas transmission leak emissi ons; 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 potent ial methane emissions from oil and
gas. Applicability to ONG Sector Facility-level data reported, limited due to report ing threshold.

Source of Data Measurements of Methane Emissions at Natural Gas Pr oduction 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, wel lheads and connectors. Estimation/ Measurement Identification of fugitives using OGI camera. The f low rate and the concentration of the leaks were measured using a Hi-Flow SamplerTM and th e mass emission rate calculated. Based on the gas composition, the percentage of car bon 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, separat ors, heaters, piping and dehydrator leaks (0.072 scf methane/min/well) from the 2013 GHG Inve ntory, 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 b enchmark.

Source of Data City of Fort Worth Natural Gas Air Quality Study, 2 011 Emissions Source Description Conducted on behalf of City to determine level of a ir pollution is being released by natural gas exploration in Fort Worth, the compliance statu s of the sites, offsite impacts of emissions, and adequacy of city-mandated setbacks. Type of Data: Collected ambient air monitoring and direct leak an d vented emissions measurements and

performed air dispersion modeling using data from 3 75 well pads, 8 compressor stations, a gas processing plant, a saltwater treatment facilit y, 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 th e total valves and connectors and the other components by TVA to determine leaks at or ab ove 500 ppmv. Gas samples from selected leaks were collected in stainless steel ca nisters 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 emis sions. Hydrocarbons with low toxicities accounted for approximately 98% of the emissions. Applicability to ONG Sector Specific to air quality issues associated with natu ral 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, 25 8 valves, 2,583 connectors, 3 condensate

tanks, 1 produced water tank, 4 thief hatches, 5 pr essure relief devices, 3 separators and 1 enclosed combustor control device.

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Estimation/ Measurement 93 emission points were identified with OGI technol ogy at the 23 production sites and emission rates were measured using a high volume sa mpler with a subset of 33 additionally sampled using evacuated canisters. A disproportiona te 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 si ngle point and instantaneous nature of the measurements, unknown if these uncollected emission s exceed the state allowance. Considering only emissions measurements with canist er 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 Wor th 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 pa d study were to improve understanding

of methane and speciated VOC emissions and investig ate 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 D etection and Repair Programs Using

Infrared Cameras, 2013 Emissions Source Description Components at gas processing plants, compressor sta tions and well sites.

Type of Data: Leak rates, types of leaking components Estimation/ Measurement Identification of fugitives using OGI and measureme nt using a high-volume sampler. In some cases, an estimate (evaluated using OGI) was u sed 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 t he 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 emissio n sources, and about 40% of the vent emissions come from instrument controllers and comp ressor 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 la rge 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 compr essor 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 an alyzed for VOC.

Methane or VOC emission factors/ emissions findings Preliminary results show median methane emission ra tes 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, h owever, not quantifiable as a sourcespecific tool. Source of Data Economic Analysis of Methane Emission Reduction Opp ortunities 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 mete rs/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 f rom the GHGRP and other studies. Estimation/ Measurement The 2011 baseline methane inventory wellhead emissi on factor for well sites, 97.6 scf/day used to estimate the total methane leak emissions f rom 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 meth ane 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.

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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 R educe Methane Losses at Four Gas

Processing Plants, 2002 and Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and Ups tream Gathering Compressor Stations and Well Sites,, 2006 Emissions Source Description 4 gas processing plants in the western U.S. and 5 g as processing plants, 12 well sites, and 7 gathering stations in the U.S Type of Data: Screening data or engineering calculation of gas fl ows into the vent and flare systems; Screening data on 101,193 individual gas service co mponents 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 hydrocarb on 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 tech niques. Methane or VOC emission factors/ emissions findings Approximately 2.6 percent of screened components we re 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 at tributed to a relatively small number of leaking components. Applicability to ONG Sector Component specific information and provided an anal ysis 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 Emis sion Estimates. The correlation equations in the Protocol can be used to estimate e missions 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 me asure 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 co sts associated with performing the screening and would depend on the number of components screen ed. Efficacy and Prevalence The portable analyzers must be calibrated using a r eference 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 dete ction 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 operat es 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 poten tially reduce the time, labor and

cost of monitoring components. Costs The capital cost of purchasing an OGI system is est imated to be $85,000 to $124,000. Provides

an analysis of cost of use in the field which range d from The EPA estimated that the OGI can monitor 1,875 to 2100 components or pieces of equip ment 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 ove rall approach of survey.

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Approach Acoustic Leak Detector Description Acoustic leak detectors are used to detect the acou stic signal that results when pressurized gas

leaks from a component. Generally, two types of aco ustic leak detection methods are used; high frequency acoustic leak detection and ultrasound le ak detection. Applicability Can be used at most facilities in the sector. Costs No cost data for acoustic leak detectors were avail able in the studies or research documents. Efficacy and Prevalence Acoustic detectors do not measure leak rates, but d o provide a relative indication of leak size

measured by the intensity of the signal. A study me asured 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 me asurements. They determined that the VPAC method was not considered to be an accurate al ternative to direct measurement for the sources tested. Approach Ambient/Mobile Monitoring Description A mobile measurement approach to investigate a vari ety 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 discov ery 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 su rvey areas and can be particularly useful in

identifying anomalous operating conditions (e.g., p ipeline 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 Systemat ic Leak Detection and Repair Programs

Using Infrared Cameras, 2013, Identification and Ev aluation 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 e ffectiveness of leak detection and repair at

natural gas processing plants and upstream compress or stations and well sites. Studies focused on gas savings as factor in economic incentive to i dentify and repair leaks Applicability Applicable for natural gas processing plants and co mpressor 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 le ss 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 a lways 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 sourc es; the EPA has rendered no technical opinion on th e underlying studies and reports; improperly defines leaks; studies referenced by the white paper appear to establish an emission rate for various types of lea king components, but these emission rates are appli ed based on an estimated component count, and therefor e yields a “potential” emission rate and not an actual emission rate; the UT study did include comp onents measured with zero emissions in the development of an average emission rate; however, o nly the components measured were included in the averaging and not the total population of component s at the location, also, the “average emissions rat e” is applied to each component, which presumes that e very component is leaking at that average rate for the entire estimation period, yielding a potential emission value and not an actual emissions value an d improperly inflates both the emissions associated w ith 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 accu rate component counts; no indication is given

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### regarding the accuracy of the leak-rate correlation and different emission factor methods and how the accuracy is impacted by the number of components co nsidered (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 natu ral gas leaks and leaks of other types of gases; th e variety of equipment configurations that can be use d in mobile measurement studies is not reflected th e white paper; did not address area and building moni toring 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 det ect 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 leve l, pressure, pressure difference or temperature. Controllers may be powered by pressurized natural g as or by other sources of power, such as solar, electric and instrument air. In many situations, ac ross all segments of the oil and gas industry, pneu matic 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 dow nstream pipeline instead of to the atmosphere.

4.1.2 Emissions Data

Source of Data Methane Emissions from the Natural Gas Industry, 19 96

Emissions Source Description Pneumatic controllers (PCs) in the natural gas prod uction, processing and transmission industry segments. Type of Data: Data on emissions and inventory of PCs at facilitie s in each studied segment extrapolated to estimate national methane emissions in 1992. Estimation/ Measurement Combination of measured emissions, manufacturers’ d ata and site visits to estimate emission and activity factors for each industry seg ment 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 = 267,09 3 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 In dustry, 1999 Emissions Source Description PCs at tank batteries in the oil production industr y segment, characterized as high bleed and low bleed. Type of Data: Used bleed rates from the GRI/EPA study above and f rom Natural Gas STAR along with estimated inventory to estimate 1995 national methane emissions. Estimation/ Measurement Assumed emission rate for high bleed PCs at the “ge neric” 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 t he split between con tinuous and intermittent PCs found in GRI/EPA. Methane or VOC emission factors/ emissions findings High bleed: 345 scfd, 157,581 PCs, 376,000 MT metha ne/yr Low bleed: 35 scfd, 292,650 PCs, 69,900 MT methane/ yr

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Applicability to ONG Sector PC inventory estimated based on oil production indu stry segment data; PC emission rates based on rates from NG production industry se gment. Source of Data Inventory of U.S. Greenhouse Gas Emissions and Sink s: 1990-2012,2014 Emissions Source Description PCs in natural gas production, processing, transmis sion and storage segments and the petroleum production segment. Type of Data: National methane emissions estimated for each segme nt; regional “potential” emissions for NG production. Emissions factors based on EPA/G RI study. Estimation/ Measurement PC emission factors trace back to EPA/GRI study, wi th 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 – n o NG STAR correction) 2012 NG transmission and storage: 249,483 MT methan e net Applicability to ONG Sector PC emission rates and inventory specific to ONG sec tor.

Source of Data Greenhouse Gas Reporting Program, 2013 Emissions Source Description PCs in three segments: onshore petroleum and NG pro duction, onshore NG transmission compression, and underground NG storag e. Type of Data: GHGRP requires source-specific emissions reports fr om all ONG facilities with GHG emissions ≥ 25,000 MT CO 2 e, 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; 8 61,224 MT methane 2012 NG transmission: 330 facilities; 7,582 MT meth ane 2012 NG storage: 38 facilities; 4,493 MT methane Applicability to ONG Sector Annual emissions data specific to ONG sector, but o nly from a subset of all facilities.

Source of Data Measurements of Methane Emissions at Natural Gas Pr oduction 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 cont rollers located at 150 distinct natural gas production sites in four production reg ions (Appalachian, Gulf Coast, Midcontinent, and Rocky Mountain) Estimation/ Measurement NG emission rates determined using a portable instr ument and converted to methane rates based on site-specific NG composition. Estima te of 2011 national methane emissions based on the number of PCs used in the GH G Inventory for 2011. Methane or VOC emission factors/ emissions findings 2011 NG production: 570,000 MT methane (with a rang e of 510,000 – 812,000 MT). Found significant unexplained geographical variabil ity in the PC emission rates between production regions (greater than a factor of 10 bet ween highest and lowest). Applicability to ONG Sector Direct emissions measurements from PCs in the NG pr oduction sector. Relied on owners for type of PCs, and only low bleed and inte rmittent were reported. Source of Data Determining Bleed Rates for Pneumatic Devices in Br itish Columbia, 2013 Emissions Source Description High bleed PCs at upstream ONG facilities in Britis h 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 du ring activations. Estimation/ Measurement NG emissions rates determined using a portable inst rument; not converted to methane rates. No attempt to estimate national or area emis sions. Methane or VOC emission factors/ emissions findings Developed NG emission factors for numerous models o f PCs and “generic” high bleed PCs and “generic” high bleed intermittent PCs. Regr ession analysis used to develop coefficients relating bleed rate to supply gas pres sure 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, Produ ction, 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 manufacture rs. Estimation/ Measurement Estimated VOC emissions for the Marcellus Shale reg ion by estimating the number of wet and dry wells in the region and establishing pe r-well NG emission factors for 2009. Per-well factors developed based on emissions facto rs 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% co nfidence 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 Opp ortunities 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 PC s, starting with the GHG Inventory for 2011 and using Allen et al., 2013. Emission fac tors for low bleed, high bleed, and two types of intermittent PCs. Added 8.6 PCs per ga thering/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 g as-driven devices that vent to the downstream

pipeline, not the atmosphere. Provide the same func tional 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 i n 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 u se. Instrument air conversion requires additional equipment to properly compress and contr ol 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 hig h concentration of pneumatic control valves

and an operator present. Because the systems are po wered by electric compressors, they require a constant source of electrical power or a backup n atural gas pneumatic device. Costs System costs are dependent on size of compressor, p ower 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 ar e 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 Bl eed Controller Description Mechanical controls operate using a simple design c omprised of levers, hand wheels, springs

and flow channels. The most common mechanical contr ol device is the liquid-level float to the drain valve position with mechanical linkages. Elec tricity or small electrical motors (including solar-powered) have been used to operate valves. So lar control systems are driven by solar power cells that actuate mechanical devices using e lectric power. As such, solar cells require some type of backup power or storage to ensure reli able operation. Applicability Application of mechanical controls is limited becau se the control must be located in close

proximity to the process measurement. Mechanical sy stems are also incapable of handling larger flow fluctuations. Electric-powered valves a re 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 d oes increase emissions. Proper methods of maintaining a device are highly variable. Applicability Enhanced maintenance to repair and maintain pneumat ic 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. Th e 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 t o limit processing problems and protect equipment. “Kimray” pumps used for glycol circulation recover energy from the high-pressure rich glycol/gas mixtu re 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, 19 96 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 p roduction segment and glycol pumps in NG production and processing segments, ext rapolated to estimate national methane emissions in 1992. Estimation/ Measurement CI pumps: Manufacturer data and limited measurement s for emission rate; site visits for inventory and duty cycle of piston and diaphragm pu mps. 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 pr ocessing: 3,215 MT methane Applicability to ONG Sector Directly applicable to ONG sector; very limited emission measurement data; lim ited site visit data. Source of Data Inventory of U.S. Greenhouse Gas Emissions and Sink s: 1990-2012, 2014 Emissions Source Description CI pumps in NG and Petroleum production segments; g lycol pumps in the NG production and processing segments. Type of Data: National methane emissions estimated for each segme nt; regional “potential” emissions for NG production. Emission factors based on EPA/GR I 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 segm ent 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 n et 2012 CI pumps in Petroleum production: 49,973 MT me thane 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 facili ties. Type of Data: GHGRP requires source-specific emissions reports fr om all ONG facilities with GHG emissions ≥ 25,000 MT CO 2 e, 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 ca lculate methane Methane or VOC emission factors/ emissions findings 2012 Pumps in onshore ONG production: 343 facilitie s; 135,227 MT methane.

Applicability to ONG Sector Annual emissions data specific to ONG sector, but o nly from a subset of all facilities. Source of Data Determining Bleed Rates for Pneumatic Devices in Br itish Columbia, 2013 Emissions Source Description CI pumps at upstream ONG facilities in British Colu mbia. Type of Data: Measurement data from 184 CI pumps. Estimation/ Measurement NG emissions rates determined using a portable inst rument; not converted to methane rates. No attempt to estimate national or area emis sions. Methane or VOC emission factors/ emissions findings NG emission factor for piston CI pumps: 0.5917 m 3 /hr (~ 20.9 scfh) NG emission factor for diaphragm CI pumps: 1.0542 m 3 /hr (~37.2 scfh) Applicability to ONG Sector Did not differentiate between NG and oil applicatio ns. Source of Data Economic Analysis of Methane Emission Reduction Opp ortunities 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 G HGRP, 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 a ir pump, 2011) Description Circulation pumps in glycol dehydration units and c hemical injection pumps are retrofitted with

instrument air to drive the pumps. Applicability Facilities with excess capacity of instrument air o r 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 compres sor 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 an nual methane

savings to be 2,500 Mcf for glycol circulation pump s 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-charge d 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 limite d to approximately 5 gallons per day

discharge at 1,000 psig. Large volume solar pumps a re 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 p ump. Efficacy and Prevalence 100% emission reduction, where applicable. The Natu ral 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 pum p, 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 electricit y, thus, they are typically installed at processing

plants or large dehydration facilities, which are n ormally 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 annu al 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 summa rizes the data available at the time the white paper was written, with one exception – the d ata 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 measurem ents were made in the Midcontinent region (0.050±0.014 scf whole gas per pump per hour). Alle n, et al. (2013) was not able to determine, from th e data collected, the reasons for the regional differ ences in emissions, which was not reflected in the emission factors from the GHG Inventory for 2012 pr esented in Table 2-14 of the white paper.


## 5.0 Compressors 5.1 Description of Process: Compressors are mechanical devices that increase th e pressure of natural gas and allow the natural gas to be transported from the production s ite, 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 (reciprocatin g compressors) of the compressor. In the production segment, compressors are used at the wel lhead to compress gas for fluids removal, and pressure equalization with gathering equipment syst ems. However, the primary use of compressors is in the natural gas processing, transmission and sto rage (particularly underground storage) segments of the industry. In the oil and natural gas sector, th e most prevalent types of compressors used are reciprocating and centrifugal compressors. In a reciprocating compressor, natural gas enters t he suction manifold, and then flows into a compression cylinder where it is compressed by a pi ston 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 mainl y 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 impe ller to increase the velocity of the gas where it is directed to a divergent duct section th at 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 indu stry segments. Centrifugal compressors are equipped with either a wet or dry seal configuratio n. Wet seals use oil around the rotating shaft to prevent natural gas from escaping where the compres sor shaft exits the compressor casing. The oil is circulated at high pressure to form a barrier again st compressed natural gas leakage. The circulated o il entrains and absorbs some compressed natural gas th at may be released to the atmosphere during the seal oil recirculation process (degassing or off- g assing). Alternatively, dry seal compressors use th e 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 i n 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 compressor s because they are a mechanically simpler design, req uire less power, are more reliable and require less maintenance.

5.2 Emissions Data

Source of Data GRI/EPA Methane Emissions from the Natural Gas Indu stry, 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 reci procating and centrifugal

compressor seals and the average number of reciproc ating and centrifugal compressors per facility to estimate the average facility emiss ions; emission factors based on screening of components using OVA and TVA. Methane or VOC emission factors/ emissions findings Production: 40 reciprocating compressor seals; emis sion factor 2.37 Mcfy per cylinder.

Processing, Transmission and Storage: Both types ofcompressors, pressurized and nonpressurized operation modes; 599 Mcfy per seal pres surized 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 centr ifugal compressors as a sum of the

emission components from compressors. These compone nts included methane emissions from compressor seals, blowdown open-ended line, pr essure relief valves, starter openended line, and miscellaneous, which includes valve s and connectors. Compressor emissions were calculated in tpy using component co unt per compressor. White paper summarized average methane emission from each segme nt in MT per year using GRI data. Source of Data Natural Gas Industry Methane Emission Factor Improv ement Study, Final Report, 2011 Emissions Source Description Focused on processes and equipment believed to cont ribute the greatest uncertainty to the

emissions inventory; fugitive leaks from transmissi on, gathering/boosting and processing compressor components including vents. Type of Data: Implications for usefulness: quality, quantity, nat ional, 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 m ethane. 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 da ta should only be a benchmark, and not used to develop emission factors due to technic al issues with measuring emissions from
compressors. Source of Data Greenhouse Gas Reporting Program, 2013 Emissions Source Description Reciprocating and centrifugal compressors in the pr ocessing, transmission and underground

storage segments and liquid natural gas import/expo rt and storage segments. Type of Data: Reported by facility, not compressor-specific, tota l methane emissions by compressor type,

number of compressors. Emission Estimation/ Measurement Prescribed in subpart W, direct measurement or engi neering 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 proc essing transmissions and storage segments. Applicability to ONG Sector Reporting threshold limits data reported; useful fo r overall sector characterization, not

emission factor development. Source of Data 

### I nventory of U.S. Greenhouse Gas Emissions and Sinks : 1990-2012, 2014 Emissions Source Description Reciprocating compressors in production through dis tribution.

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

seal centrifugal compressors in production, process ing, transmission, storage segments. Emissions Estimation/ Measurement Uses GRI/EPA emission factors developed in 1996 stu dy.

Methane or VOC emission factors/ emissions findings Inventory reports nationwide 2012 based on 2012 act ivity and factors current emissions.

Applicability to ONG Sector Valuable for recent activity data and overall chara cterization 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 na tural gas sector.

Type of Data: Used the emission factors from the GRI/EPA study an d 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 factor s, 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 cent rifugal 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 Invent ory. 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 in cluded 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 indust ry which including centrifugal and

reciprocating compressors. Type of Data: Study used emissions baseline from previous ICF 201 1 which updated 2013 GHG

inventory numbers to project emissions to 2018. Emissions Estimation/ Measurement Different methods were used for each segment to pro ject 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 emission s factors or emissions data.



### 5.3 Mitigation Approaches Approach Reciprocating Compressor - Rod Packing Replacement Description Replacement of the compressor rod packing, replacem ent 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 a t a cost of $1620 per cylinder. Capital

cost per compressor in production $6,480 with gas s avings 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 stora ge capital cost of $7,290 with gas savings of $2,276. Efficacy and Prevalence Per compressor methane emission reductions; Product ion 0.158 tpy, gathering and boosting

6.84 tpy, processing 18.6 tpy, transmission 21.7 tp y and storage 21.8 tpy. VOC emission reductions: production 0.04 tpy, gathering and boos ting 1.9 tpy, processing 5.18 tpy, transmission 0.6 tpy, and storage 0.6 tpy. Prevale nt 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, particularl y for processing plants due to availability

of processes to use gas. Costs Cost data not available for a gas recovery system t hat 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 use d 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 compresso r. Results in emissions reductions, higher

reliability, and overall maintenance and operating costs. Applicability Applicable for most centrifugal compressors, howeve r, not all. Due to size and certain

applications, certain wet-seal compressors cannot b e replaced with dry seal compressors. Costs For processing, transmission and storage, capital c ost of $75,000 and annual operation and

maintenance savings of $88,300. Processing also rea lizes 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 compres sor 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 indus try.

Approach Centrifugal Compressor - Wet Seal with gas recovery for use onsite Description Capture emissions and route to some process operati on. 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 est imated annual gas savings of $44,729 and $24,849 for the transmission and storage segmen ts. Efficacy and Prevalence 95% emissions reduction. Not prevalent in the indus try.



### 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 t he pressure is not sufficient to facilitate the flo w of accumulated water and hydrocarbon liquids to the su rface along with produced gas. When this occurs, this accumulation of liquids can impede and sometim es halt gas production. When the accumulation of liquid results in the slowing or cessation of gas p roduction (i.e., liquids loading), removal of fluid s (i.e., liquids unloading) is required in order to maintain production. Emissions to the atmosphere during liquids unloading events are a potentially signific ant 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 syst em can be used which uses the well’s own energy (gas/pressure) to lift liquids from the tubing by p ushing the liquids to the surface by the movement o f a free-traveling plunger ascending from the bottom of the well to the surface. The plunger essentially a cts as a piston between liquid and gas allowing the ope rator 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 CO 2 e; wells that are venting, with and without plunger li ft operation; annual reporting. Type of Data: Nationwide, limited by reporting threshold, facilit ies report methane emissions and number of venting wells, whether or not equipped wi th plunger lift. Emissions Estimation/ Measurement Subpart W provided defines 3 methods, direct measur ement 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 lim ited due to reporting threshold and reporting requirements and methods. Facility report ing 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 pet roleum 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 wel ls 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 s pecific notations, possibly correlating more to geographic and basin applicabil ity. Source of Data Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production: Summary and Analysis of API and ANGA Survey Respons es 2012 Emissions Source Description 20 companies covering 90,000 gas wells, including g as wells that conduct liquids unloading. Type of Data: Well-level data methane emissions. Emissions Estimation/ Measurement Used 40 CFR part 98, subpart W engineering equation s to estimate emissions using well-specific data on well bore volume, well pressu re, 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; aut hors found that EPA emission estimates were highly overestimated; most of the em ission were produced by less than 10 percent of the well population. Applicability to ONG Sector Provided well-specific data on wells that conduct l iquids 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 Pr oduction 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 intermit tent 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 ev ent; 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 Opp ortunities in the U.S. Onshore Oil and Natural Gas Industries (ICF International, 2014 Emissions Source Description Study of economic analysis of methane emissions red uction opportunities; 22 different emission sources in industry, including liquids unl oading. Type of Data: Used data from 2013 GHG inventory and UT Allen stud y. Emissions Estimation/ Measurement Updated emissions baseline to calculate emission fa ctors 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 estimate s 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/pressu re) to drive a piston or plunger that travels

the length of the tubing in order to push accumulat ed 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 pressu re and liquid to gas ratio can affect applicability. Candidate wells for plunger lift sys tems 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 complexit y 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 lea rned 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 plunge r lift systems (e.g., with smart well automation) can decrease the amount of gas vented b y 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 t o 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 d ownhole pump technology. Costs Capital and installation costs (includes location p reparation, 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 p roduces 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 tubi ng and reduces the cross-sectional area of

flow, increasing the flow velocity and achieving li quid 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 vol ume natural gas wells upon initial completion

or near the end of their productive lives with rela tively small liquid production and higher reservoir pressure. Candidate wells include margina l gas wells producing less than 60 Mcfd. Coil tubing can also be used in wells with lower ve locity 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 ins tallation costs provided from industry include: $7,000-$64,000/well. Efficacy and Prevalence Considered to be a “no emissions” solution. Low mai ntenance, 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 s tream. 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 becau se 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 una ble to unload fluid, additional, smaller tubing may be needed to help lift the fluids. Foami ng agents work best if the fluid in the well is at least 50% water. Surfactants are not eff ective for natural gas liquids or liquid hydrocarbons. Foaming agents and velocity tubing ma y be more effective when used in combination. Costs Foaming agents are low cost. No equipment is requir ed in shallow wells. In deep wells, a

surfactant injection system requires the installati on of surface equipment and regular monitoring. Pump can be powered by solar or AC powe r or actuated by movement of another piece of equipment. Capital and startup costs to in stall soap launchers: $500- $3,880. Capital and startup costs to install soap launchers and velocit y 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 vol ume method applied early in production

decline when bottom-hole pressure still generates s ufficient 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 whit e 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 misunde rstandings scattered throughout the paper; the paper does not discuss the limitations of the under lying sources of information and no critical analys is of the accuracy or validity of the sources; the pap er does not provide analysis of data, only a summar y; 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. Instal lation or use of plunger lifts are a technique in t he management of unloading of liquids from wells, howe ver, use of PLs does not mean “venting” will be eliminated or reduced; the white paper was erroneou s 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 em ission factor based solely on venting wells does not accurately characterize the effectiveness of th is control technology for eliminating emissions fro m the majority of wells; and since the GHGRP only inc ludes emissions from facilities above the 25,000 MT CO 2 

### e 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 e missions

.

## Small Business Advocacy Review Panel

Panel Outreach Meeting with Small Entity Representa tives 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 Pol icy (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 (O IRA)

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 abo ve. 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 AdministratorOffice of PolicyOffice of Regulatory Policy and Managementhttp://www.epa.gov/op/orpm.htmlA Refresher on the Small BusinessAdvocacy Review Panel ProcessAlexander Cristofaro, Small Business Advocacy Review Chair (SBAC)Panel Outreach Meeting, June 18, 2015Today’s Topics• What is a Small Business Advocacy Review (SBAR)Panel?• Your role as a Small Entity Representative (SER)• The difference between an SBAR Panel and a proposedregulation2What 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(OIRA)SBA’s Office of Advocacy• The Regulatory Flexibility Act (RFA) instructs thePanelto:Review “any material the agency has prepared” related to thedevelopment of the regulationCollect advice and recommendations from SERsPrepare a report within 60 days of the Panel conveningSee Title 5, section 609(b)(3)-(5), of the**United States Code**(USC). This is also known as section 609(b)(3)-(5) of theRegulatory Flexibility Act (RFA).3What is an SBAR Panel?(cont’d.)• The types of materials the Panel will review and on which you, the SERs,will provide advice and recommendations are specified by law• Section 609(b)(4) of the RFA states that “the panel shall review anymaterial the agency has prepared...on issues relatedto”:“a description of and, where feasible, an estimateof the number of small entitiesto which the proposed rule will apply” (Sec. 603(b)(3))“a description of the projected reporting, recordkeeping and other compliancerequirements of the proposed rule, including an estimate of the classes of smallentities which will be subject to the requirement and the type of professionalskills necessary for preparation of the report or record” (Sec. 603(b)(4))“an identification, to the extent practicable, of all relevant Federal rules whichmay duplicate, overlap or conflict with the proposed rule” (Sec. 603(b)(5))“a description of any significant alternatives to the proposed rule whichaccomplish the stated objective of applicable statutes and which minimize anysignificant economic impact ...on small entities” (Sec. 603(c))4Your role as a SER• EPA values this SBAR Panel process because it provides us withimportant small entity perspectives and information• Your verbal and written input is considered and valued by the Panelas the Panel develops the Panel report• Copies of your written comments will be appended to the PanelReport and a chapter in the Panel report will summarize them.• The Panel will consider the comments you provide to us, but thefindings that ultimately appear in the report are those of the Panelmembers: EPA, OMB, and SBA• The Administrator will carefully consider the input we gather fromthe SERs and the Panel members, but is not legallybound to adoptthe recommendations of the Panel5The difference between an SBAR Paneland a proposed regulation• SBAR PanelReviews materials related to:• the impacts of the regulation on small entities• Federal rules which may intersect with this proposed regulation• Alternatives to the regulation that may minimize small entityimpactsEPA uses the Panel report to inform our decision-making aboutthe forthcoming proposed regulation• Proposed regulationFully formed regulatory proposal or set of regulatory alternativesYou will have an opportunity to comment on the proposal, justlike any other public citizen6Thank You• Participation is voluntary and we appreciate the time andenergy you put towards this rulemaking.• Thank you - we know it is, and has been, an intenseresource commitment.• Contact my staff:Nicole OwensEPA Office of Policyowens.nicole@epa.gov7Panel Outreach Briefing: EmissionStandards for New and ModifiedSources in the Oil and Natural GasSectorJune 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 Steps2**Deliberative - Do Not Cite or Quote**Oil and Gas Sector DescriptionLeaks from unprotected steel mains and service linesPicture courtesy ofAmerican GasAssociationWell completionsOil ProductionStorage tanksCompressorsGlycol dehydratorsPneumatic controllersWell completionsNatural Gas Production & ProcessingVenting of gas for maintenance or repairof pipelines or compressorsLeaks from compressor stationsGas TransmissionLeaks at metering and regulating stationsGas DistributionPipeline blowdownsProcessing plant leaksCovered in Oil and GasWhite PapersLiquids UnloadingStorage tanksFugitive EmissionsProduced Water Evaporation PondsGas plant sweetening unitsCompressorsStorage tanksGlycol dehydratorsPneumatic ControllersPneumatic ControllersFugitive EmissionsPneumatic controllersPneumaticpumpsPneumatic pumps3**Deliberative - Do Not Cite or Quote**Oil and Gas Sector – Current Regulatory CoverageLeaks from unprotected steel mains and service linesPicture courtesy ofAmerican GasAssociationWell completionsOil ProductionStorage tanksCompressorsGlycol dehydratorsPneumatic controllersWell completionsNatural Gas Production & ProcessingVenting of gas for maintenance or repairof pipelines or compressorsLeaks from compressor stationsGas TransmissionLeaks at metering and regulating stationsGas DistributionPipeline blowdownsProcessing plant leaksLiquids UnloadingStorage tanksFugitive EmissionsProduced Water Evaporation PondsGas plant sweetening unitsCompressorsStorage tanksGlycol dehydratorsPneumatic ControllersPneumatic ControllersFugitive EmissionsPneumatic controllersPneumaticpumpsPneumatic pumpsNew and Existing Sources CoveredOnly New Sources CoveredCovered in White Papers4**Deliberative - Do Not Cite or Quote**White House Announcement►On January 14, 2015, the White House announced itspathforward 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 equipmentand processes to those source types currently covered byNSPS standards – note: the controls for GHG and VOCemission reductions are the same.►Specifically look at sources from the Oil and Gas WhitePapers•Hydraulically Fractured Oil Well Completions,•Fugitive Emissions,•Pneumatic Devices,•Compressors, and•Liquids Unloading.5**Deliberative - Do Not Cite or Quote**Coverage of white paper sources under 2012 NSPS►Well Completions (hydraulically fractured gas wells)►Equipment Leaks (at natural gas processing plants)►Pneumatic Controllers (through gas processing)►Compressors (through gas processing, excluding wellsitecompressors)►Liquids Unloading (not addressed in 2012 NSPS)6**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 barrelsper day – 22% of wells)►Appropriate pressure threshold- are there particularconsiderations for oil wells?►Is the use of GOR an appropriate approach for establishing athreshold (e.g., 300 or 500 scf gas per barrel, 24% and30% ofwells respectively)?Hydraulically Fractured Oil Well CompletionsOilGas2012 NSPSWhite Paper SourceNot Applicable7**Deliberative - Do Not Cite or Quote**Hydraulically Fractured Oil Well Completions – Control Options2012 NSPSWhite Paper SourceNot ApplicableOption Description Applicability/Effectiveness Estimated Cost RangeReducedEmissionCompletions“Green” or “flareless” completions, usespecially designed equipment at the wellsite to capture and treat gas so it can bedirected to the sales line. Additionalequipment required to conduct a RECmay include additional tankage, specialgas-liquid-sand separator traps, and a gasdehydrator. Portable equipment used forRECs can operate in tandem with thepermanent equipment that will remainafter well drilling is completed.Some limitations exist for performingRECs since technical barriers fluctuatefrom well to well: proximity ofpipelines, pressure of produced gas,and inert gas concentration. Emissionsreductions will vary according toreservoir characteristics and otherparameters. Any amount of gas thatcannot be recovered can be directed toa completion combustion device inorder to achieve a minimum 95 percentreduction in emissions.Equipment costs associatedwith RECs vary from well towell. A REC lasting 7 days isestimated to be between$10,000 and $15,000 percompletion.CombustionCompletion combustion is a hightemperature oxidation process used toburn combustible components, mostlyhydrocarbons, found in waste streams.Combustion devices are rather crudeand portable, often installedhorizontally due to the liquids thataccompany the flowback gas. The flowdirected to a completion combustiondevice may or may not be combustibledepending on the inert gascomposition of flowback gas, whichwould require a continuous ignitionsource. Combustion devices do notemploy an actual control device, andare not capable of being tested ormonitored for efficiency.Combustion estimatedannual cost rangesbetween $3,000 and$4,000 per wellcompletion.8**Deliberative - Do Not Cite or Quote**►2012 NSPS includes equipment leaks (at natural gasprocessing 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 program as amodel (We heard: burdensome with little environmental benefit,frequency of inspections and reporting too costly, lack ofair qualitymodeling to quantify expected reductions, loss of marginal wells)►Input requested from SERs►Expand on issues with Colorado Regulation 7 implementation►Appropriate exemption threshold (e.g. 2.7 tons per year in PA, lowproducing wells or stripper wells)►Feedback on appropriate flexibility or exclusions undercertaincircumstancesOilGas2012 NSPSWhite Paper SourceNot ApplicableFugitive Emissions9**Deliberative - Do Not Cite or Quote**Fugitive Emissions – Control Options10Option Description Applicability/Effectiveness Estimated Cost RangeOptical Gas Imaging –“Infrared Camera”OGI operates much like aconsumer video-camcorder andprovides a real-time visual imageof hydrocarbon gas emissions orleaks to the atmosphere. The OGIcamera works by using spectralwavelength filtering and an array ofIR detectors to visualize the IRabsorption of hydrocarbons andother gaseous compounds. As thegas absorbs radiant energy at thesame waveband that the filtertransmits to the detector, the gasand motion of the gas is imaged.OGI instrument can beused for monitoring alarge array of equipmentand components at afacility, and is an effectivemeans of detecting leakswhen the technology isused appropriately.Information in the whitepaper related to thepotential emissionreductions from theimplementation of anOGI monitoring programvaried from 40 to 99percent.It is believed that the OGI system canreduce the cost of identifying fugitiveemissions at oil and natural gas facilitieswhen compared to using a handheld TVAor OVA. The annual cost for OGI (wellpads) ranges between $1,500 and $2,000;OGI (gathering/boosting) ranges between$9,000 and $10,000; and OGI(transmission/storage) ranges between$13,000 and $23,000. The annual cost forMethod 21 (well pads) ranges between$1,500 and $3,000; Method 21(gathering/boosting) ranges between$10,000 and $15,000; and Method 21(transmission/storage) ranges between$7,000 and $25,000.Frequency of SurveysThe reduction of fugitive emissionsinvolves the development of afugitive emissions monitoring plan.An exemplary plan mayincorporate semiannual survey.The estimated annual cost of monitoringfugitive emissions will vary based on thefrequency of the monitoring planactivities and type of monitoring.**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 vaporrecovery)►Pre-panel SER written comments►Gas processing plants have a very small number ofpneumatic pumps, and provide little benefit in emissionsreductions from gas processing.►Input requested from SERs►What is the prevalence of control devices already at yourfacilities?►Are there site characteristics that make control devices moreprevalent? (e.g. storage vessels)Pneumatic PumpsOilGas2012 NSPSWhite Paper SourceNot Applicable11**Deliberative - Do Not Cite or Quote**Pneumatic Pumps – Control Options12Option Description Applicability/Effectiveness Estimated Cost RangeConvert to Solar PumpsSolar power cells can generate electricity topower the pump. Solar cells can utilize aback-up power system to ensure reliability.Solar powered pumps are only reliable in areaswhere the sun can power the pump reliably.These devices, when applicable can result in100 percent reduction in emissions whereapplicable.Capital costs for converting to solarpumps is approximately $2,300 perdeviceCovert to Electric PumpsElectric pumps can be used where a reliablesource of electricity is available at thefacility.Electric powered pumps are only reliable with aconstant supply of electricity. Overall, thisoption is applicable in niche areas but canachieve 100 percent reduction in emissionswhere applicable.Capital costs range between $1,800to $5,500 plus electricity costs and anaverage annual maintenance cost of$260 per device.Convert to Instrument AirInstrument air systems can be used byreplacing compressed air for the gas inpumps. These systems include acompressor, electrical power source, airdehydrator (depending on the type ofpump), and volume tank.Instrument air systems reduce emissions by 100percent by replacing natural gas withinstrument air. This technology offerseconomies of scale, where it is moreeconomical at facilities with more pneumaticpumps. The system requires a reliable source ofelectrical power.System costs are dependent on sizeof compressor, power supply needs,labor and other equipment.Estimated annualized range isbetween $800 and $8,000.Route natural gas to anExisting Control DeviceRouting natural gas from a gas-driven pumpentails piping to a control device inletstream.Routing natural gas pumps to a combustiondevice reduces VOC and CH4emissions by 95percent. Routing natural gas to a control deviceis an option when a control device withavailable capacity is present on site.Costs will vary depending on thedistance of pipeline necessary, butannualized cost is estimated between$200 and $300.Route natural gas toNewly Installed ControlDeviceRouting natural gas from a gas-driven pumpto a control device requires installation of acontrol device and piping between thepump and the control device.Routing natural gas-driven pumps to acombustion control device typically reducesVOC and CH4emissions by 95 percent.Capital costs will be approximately$48,000 with annual costs around$105,000.Route Natural Gas toExisting Gas CaptureSystemRouting natural gas from a gas-driven pumpentails piping to a vapor recovery unit (VRU).Routing natural gas-driven pumps to a VRUreduces VOC and CH4emissions through gascapture where emission reduction efficienciesare typically 95 percent.Capital costs will vary depending onthe distance of pipeline necessary,but are estimated to beapproximately $1,500 per device.**Deliberative - Do Not Cite or Quote**►2012 NSPS covers pneumatic controllers in theproduction 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 gasprocessing operations►Input requested from SERs►How many small entities own gas processing plants?►What is the prevalence of instrument air at gas processingplants?Pneumatic ControllersOilGas2012 NSPSWhite Paper SourceNot Applicable13**Deliberative - Do Not Cite or Quote**Pneumatic Controllers – Control Options14Option Description Applicability/Effectiveness Estimated Cost RangeInstall Low BleedDevice in Place ofHigh Bleed DeviceLow-bleed devices provide the same functionalcontrol as a high-bleed device, while emitting lesscontinuous bleed emissions.Applicability may depend on the functionof instrumentation for an individual deviceon whether the device is a level, pressure,or temperature controller.Low-bleed devices are,on average, around $160more than high bleedversions. Annualized costranges $20 to $30.Convert toInstrument AirCompressed air may be substituted for natural gas inpneumatic systems without altering any of the partsof thepneumatic control. In this type of system, atmospheric airis compressed, stored in a tank, filtered and thendried forinstrument use. For utility purposes such as smallpneumatic pumps, gas compressor motor starters,pneumatic tools and sand blasting, air would not need tobe dried. Instrument air conversion requires additionalequipment to properly compress and control thepressured air. This equipment includes a compressor,power source, air dehydrator and air storage vessel.Replacing natural gas with instrument air inpneumatic controls eliminates VOC emissionsfrom bleeding pneumatics. These systems canachieve 100 percent reduction in emissions. Itis most effective at facilities where there are ahigh concentration of pneumatic controlvalves and an operator present. Since thesystems are powered by electric compressors,they require a constant source of electricalpower or a back- up natural gas pneumaticdevice.System costs aredependent on size ofcompressor, power supplyneeds, labor and otherequipment. Annualized costis estimated to be between$2,000 and $20,000.Mechanical andSolar PoweredSystems in place ofBleed DeviceMechanical controls operate using a simple designcomprised of levers, hand wheels, springs and flowchannels. The most common mechanical control deviceisthe liquid-level float to the drain valve positionwithmechanical linkages. Electricity or small electrical motors(including solar powered) have been used to operatevalves. Solar control systems are driven by solar powercells that actuate mechanical devices using electric power.As such, solar cells require some type of back-up power orstorage to ensure reliability.Application of mechanical controls islimited because the control must belocated in close proximity to the processmeasurement. Mechanical systems are alsoincapable of handling larger flowfluctuations. Electric powered valves areonly reliable with a constant supply ofelectricity. Overall, these options areapplicable in niche areas but can achieve100 percent reduction in emissions whereapplicable.Depending on supply ofpower, costs can rangefrom below $1,000 to$10,000 for entiresystems.**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 burdensome tosmall 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?CompressorsOilGas2012 NSPSWhite Paper SourceNot Applicable15**Deliberative - Do Not Cite or Quote**Compressors – Control Options16Option Description Applicability/Effectiveness Estimated Cost RangeReciprocatingCompressors- RodPacking ReplacementOver time the packing rings wearand allow more natural gas toescape around the piston rod.Regular replacement of these ringsreduces CH4and VOC emissions.Piston rods, wear more slowly thanpacking rings, having a life of about 10years. We assume operators willchoose, at their discretion, when toreplace the rod.The estimated rodreplacement cost range isbetween $1,700 and $2,100.CentrifugalCompressors- DrySealsCentrifugal compressor dry sealsoperate mechanically under theopposing force created byhydrodynamic grooves and springs.Dry seals substantially reduce gasemissions compared to wet seals. Atthe same time, they significantlyreduce operating costs and enhancecompressor efficiency compared to wetseals.The replacement of wet sealswith dry seals is estimated costsavings range of $80,000 to$90,000.CentrifugalCompressors- WetSeal with flare or gasrecoveryThese seals use oil, which iscirculated under high pressurebetween three rings around thecompressor shaft, forming abarrier against the compressed gasleakage. The oil barrier allowssome gas to escape from the seal,but considerably more gas isentrained and absorbed in the oilunder the high pressures.As a control measure, the recoveredgas would then be sent to acombustion device or other process.The annual cost of wet sealwith gas recovery rangesbetween $3,000 and $5,000.**Deliberative - Do Not Cite or Quote**►Not covered in 2012 NSPS►Control Options►Route Emissions to Flare►Plunger Lift Systems►Artificial Lift Systems►Velocity Tubing►Foaming Agents►Cost is highly variable based on well characteristics►Pre-panel SER written comments►Noted complexity of well liquid unloading►Regulatory uncertainty►Input requested from SERs►During a blowdown, is it feasible for emissions to be routed to aflare?►What are the techniques you currently use?►Do you have an estimated number of potentially affectedsources?Liquids UnloadingOilGas2012 NSPSWhite Paper SourceNot Applicable17**Deliberative - Do Not Cite or Quote**►Options►Retain 2012 REC-PIX alternative►Electronic reporting►Pre-panel SER written comments►Limitation of small number staff►High cost and difficulty of obtaining third-party contractors►Concerned with duplicative efforts►Input requested from SERs►Please share other ideas to help streamline potentialduplications.►Are you familiar with the REC-PIX alternative to wellcompletion reporting in the current NSPS (2012)?►Do you find the provision for well completion notificationhelpful in reducing duplicative reporting (notification under astate or local requirement satisfies the NSPS)?Reporting & Recordkeeping18**Deliberative - Do Not Cite or Quote**Number of Potentially Affected SourcesEmissions Source No. Of Potentially AffectedNew Sources AnnuallyOil Well Completions 10,000 to 20,000Fugitive Emissions 15,000 to 25,000Pneumatic Pumps 2000 to 3000Compressors 50 to 100Pneumatic Controllers 200 to 300Liquids Unloading unknown19**Deliberative - Do Not Cite or Quote**Unit Reductions and Costs from Potential Control OptionsEmissions Source Control OptionsBaseline Emissions (tons per year) Emission Reduction (tons per year)Natural GasProductRecovery(Mcf/year)Annualized Costwith Savings(2012$)Methane VOC Methane VOCOil Well CompletionsReduced EmissionCompletion9-10 8-9 9-10 7-8800-900 $10,000-$15,000Combustion9-10 8-9 9-10 7-80 $3,000-$4,000Fugitive Emissions -Well PadsOGI 1-5 0-2 0-4 0-2 30-160 $1,500-$2,000Fugitive Emissions -Gathering/BoostingStationsOGI 30-40 9-10 10-35 3-8 1,100-1,300 $9,000-$10,000Fugitive Emissions -Transmission andStorage CompressorStationsOGI 60-170 1-5 20-140 0-4 1,500-5,500 $13,000-$23,000Pneumatic Pumps –Production andProcessingRoute Emissions toExisting Control Device0-4 0-1 0-4 0-1 0 $200-$300Instrument Air 0-4 0-1 0-4 0-1 0$800-$8,000Pneumatic Pumps –Transmission andStorageRoute Emissions toExisting Control Device0-4 0-1 0-4 0-1 0 $200-$300Instrument Air 0-4 0-1 0-4 0-1 0$800-$8,000CompressorsRod PackingReplacement25-35 0-1 20-30 0-1 1,000-1,200 $1,700-$2,100Replace Wet Seals withDry100-160 3-5 100-140 3-5 5,000-6,000($80,000) to($90,000)Wet Seal with GasRecovery100-160 3-5 100-160 3-55,000-6,000 $3,000-$5,000Route Emissions toControl100-160 3-5 100-150 3-5 0$110,000-$120,000Pneumatic ControllersInstall Low- or No-bleedControllers3-4 0-1 2-4 0-1 140-150 $20-$30Instrument Air 3-4 0-1 3-4 0-1140-150$2,000-$20,000**Deliberative - Do Not Cite or Quote**Additional SER Input RequestedThe Regulatory Flexibility Act (RFA) statute directs the Panel to collect advice andrecommendations from SERs on issues related to:►603(b)(3) a description of and, where feasible, an estimate of the number ofsmall entities to which the proposed rule will apply;►603(b)(4) a description of the projected reporting, recordkeeping and othercompliance requirements of the proposed rule, includingan estimate of theclasses of small entities which will be subject to the requirement and the typeof professional skills necessary for preparation of the report or record;►603(b)(5) an identification, to the extent practicable, of all relevant federal ruleswhich may duplicate, overlap or conflict with the proposed rule►603(c) each initial regulatory flexibility analysis shall also contain a descriptionof any significant alternatives to the proposed rule which accomplish the statedobjectives of applicable statutes and which minimize any significant economicimpact of the proposed rule on small entities; consistentwith the statedobjectives of applicable statutes, the analysis shall discuss significantalternatives such as:►The establishment of differing compliance or reporting requirements ortimetables that take into account the resources available to small entities;►The clarification, consolidation, or simplificationof compliance and reportingrequirements 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 partthereof, for such smallentities21**Deliberative - Do Not Cite or Quote**Next Steps►In addition to comments we heard today, written commentswill be accepted by the panel (EPA, OMB, and SBA) byJune 29, 2015.►Final report of this panel process will be developed in theJuly timeframe►Proposal of the NSPS planned for summer 201522

### 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 operatin g costs are annualized over the assumed technology life using a 7% interest rate.

• Cost analysis are based on model facilities and typ ical costs.
Oil Well Completions:

• Activity data

o Baseline completions count based on HPDI dataset fo r 2012. Classification of oil wells based on gas-to-oil ratio (GOR).

o Projection of change in completions from 2012 throu gh analysis years based on projections in AEO14/NEMS.

o Classification of development versus delineation/ex ploration wells based on AEO14/NEMS.

• Emissions

o Emissions per day based on gas production in the fi rst 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 fl are based on white papers.

o Assumption that RECs will be feasible for 50% of oi l well completions (whereas for the remainder RECs will likely be infeasible fo r some combination of unavailability of infrastructure or other technical considerations).

• Costs

o Costs per day for REC equipment based on white pape r and 2012 NSPS supplemental TSD, adjusted for inflation.

o Costs per completion combustion device based on 201 2 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 analysi s of HPDI dataset for 2012.

o Projected change in wellpads from base year to proj ection years based on AEO14/NEMS.

o Typical new compressor stations per year based on h istorical 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 com pressor 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 Inv entory.

### • 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 com parison to other analyses such as Carbon Limits and Colorado rule analysis. C osts for repairs, overhead, planning, and program support based on per-hour est imates and typical labor
rates.
Pneumatic Pumps:

• Activity data

o Typical new pneumatic pumps per year based on histo rical average of increases in number of pumps per year from the U.S. GHG Inventor y.

o Consideration of two pump types/sizes (diaphragm/he at-trace and piston/plunger pump).

o Pumps primarily analyzed at well sites.

o Consideration of pumps located at sites where contr ols 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 typic al 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. GH G Inventory.

o Assumption that a portion of high-bleed pneumatic c ontrollers are needed for operational reasons and cannot be replaced with low -bleed controllers.

• Emissions

o Emissions per controller based on white paper and 2 012 NSPS analysis.

• Costs

o Costs based on incremental cost difference between a low-bleed and high-bleed pneumatic controller, from white paper and 2012 NSP S analysis.
Compressors:

• Activity data

o Typical new wet seal compressors and reciprocating compressors in transmission and storage based on historical average of increase s in number of such controllers in the U.S. GHG Inventory.

### • Emissions

o Emissions per compressor based on white paper and 2 012 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 Assump tions** 


# 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

Combustion 1 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 est imated 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 producti on per event. It is assumed CH 4 

### comprises 46.732 percent by volume of natural gas. (Factors: 0.0208 tons CH 4 

### per Mcf and 0.8374 lb. VOC/lb. CH 4 

### ) 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 Consul ting. Percent of Emissions Recovered by Reduced Emission Completions. May 2011.

 Any amount of gas that cannot be recovered can be d irected to a completion combustion device in order to achieve a minimum 95 percent reduction in emissions

.

 95 percent recovery was estimated based on 90 perce nt of flowback being captured to the sales line and assuming an additional 5 percent of the remaining f lowback would be sent to the combustion device. (2011 TSD, p 4-28)

 Combustion

 Assumes destruction efficiency of 95 percent, consi stent with the expected destruction efficiency of a properly designed and operated flare for completion combusti on 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 t o be $12,735 ($13,459 in 2012$) for a representativ e 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 w ell completions. For example, REC will be required where feasible, and c ombustion where an REC is not feasible.

2 EPA is only considering regulating hydraulically f ractured or refractured oil wells with gas oil rati os greater than 300.

3 Memorandum to Bruce Moore, U.S. EPA from Heather B rown, 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 com pressor station based on GRI/EPA, which underlies t he U.S. GHG Inventory for this source. Equipment and compon ent counts for oil wells based on GHG Inventory. Ga s Research Institute (GRI)/U.S. EPA. Research and Development, Methane Emissions from th e Natural Gas Industry, Volume 8: Equipment Leaks. June 1996 (EPA-600/R-96-080h). http://www.epa.gov/gasstar/documents/emissions_repo rt/8_equipmentleaks.pdf



## Emission Reduction

 Emissions factors per component based on AP-42.

 U.S. EPA, Protocol for Equipment Leak Emission Esti mates, 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 O GI monitoring program varied from 40 to 80 percent (assumptions: 40% - annual inspections; 60% - semia nnual inspections; 80% - quarterly monitoring).

 Ranges account for the varying efficacies of quarte rly, semiannual, and annual monitoring.



## Costs

 Costs for OGI surveys based on white papers and com parison to other analyses such as Carbon Limits and Colorado rule analysis. Costs for repairs, overhead, plannin g, and program support based on per-hour estimates and typical labor rates.

 Colorado Air Quality Control Commission, Initial Economic Impact Analysis for Proposed Revis ions to Regulation Number 7 (5 CCR 1001-9). November 15, 2013. https://www.colorado.gov/pacific/sites/default/file s/062_R7-Initial-EIA-request-11-21-13-26-pgs-062_1. pdf

 Carbon Limits. Quantifying cost-effectiveness of systematic LDAR P rograms using IR cameras. December 24,
2013. http://www.catf.us/resources/publications/files/CAT F-Carbon_Limits_Leaks_Interim_Report.pdf

 Labor rate: $57.80/hour. Source: Table 11 of the Un iform Standards memo - Memorandum to Jodi Howard, EPA/OAQPS from Cindy Hancy, RTI International, Anal ysis of Emission Reductions Techniques for Equipmen t 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 pisto n and diaphragm pumps

 Piston Pumps: Methane emissions range from 0-0.5 tp y; VOC from 0-0.25 tpy; varying based on location

 Diaphragm Pumps: Methane emissions range from 3-4 t py; VOC from 0.5-1 tpy; varying based on location

 Data Sources: EPA/GRI. Methane Emissions from the N atural Gas Industry, Volume 13: Chemical Injection Pumps. June 1996 (EPA-600/R -96-080m), Sections 5.1 – Diap hragm Pumps and 5.2 – Piston Pumps



## Emission Reductions

 Route to Control - Capture systems combined with co mbustion devices are considered a reliable mechanis m 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 Che mical 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 com bustor 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 Syst em – 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 p umps, with varying distribution scenarios between diaphragm and piston pumps (ie, 50/50;75/25; 25/75)

 The compressor costs used in our analysis were draw n from the costing analysis conducted for the 2011 NSPS proposal for instrument air systems for pneuma tic 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 pe r 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 t o 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 Ind ustry, 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 emis sion from reciprocating compressor rod packing was to use the CH4 emission factors referenced in the EPA/GRI stud y 4 

### and the CH4-to-VOC ratio developed in the gas comp osition memorandum.

 Centrifugal - The compressor emission factors for w et seals and dry seals are based on data used in th e GHG Inventory 5 

### . 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 b ased on data collected by the Natural Gas STAR Prog ram. 

## Emission Reductions

 Reciprocating

 The emission reductions for the transmission and st orage segments were calculated by multiplying the number of new reciprocating compressors in each seg ment by the difference between the average rod packing emission factors and the average emission f actor for newly installed rod packing.

 Centrifugal

 Dry seals - The dry seal emission factor is based o n information from the Natural Gas STAR Program. 6



###  Route to Control - A combustion device typically ac hieves 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 c ylinder

 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 assessm ent.

 On average, each reciprocating compressor has 3.3 c ylinders.

 Replace every three years, during planned shutdowns and maintenance

4 National Risk Management Research Laboratory. GRI/ EPA Research and Development, Methane Emissions fro m the Natural Gas Industry, Volume 8: Equipment Leaks. Prepared for t he U.S. Department of Energy, Energy Information Ad ministration. EPA-600/R96-080h. June 1996.

5 U.S. EPA. Methodology for Estimating CH 4 and CO 2 Emissions from Petroleum Systems. GHG Inventory: E mission 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 saving s from the installation of dry seal compressor is $88,300 in comparison to wet seal compressor.

 http://www.epa.gov/gasstar/documents/ll_wetseals.pd f . See p. 4, Exhibit 4.

 Route to Control - The capital and annual cost of t he 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 emission s from 0.2 scfh up to 5 scfh and high-bleed devices vary significantly from venting as low as 7 scfh to as h igh as 100 scfh.

 U.S. EPA. GHG Emissions Reporting From the Petroleu m and Natural Gas Industry: Background TSD. Climate Change Division. Washington, DC. November 2010.

 EPA determined that best available emissions estima tes for pneumatic controllers are presented in Tabl e W-3 of the GHG Mandatory Reporting Rule for the Oil and Na tural 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 f rom 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 $2,4 71, while the average cost for a low bleed is $2,69 8. incremental cost of installing a low-bleed device i nstead 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 us ing a 7 percent interest rate. This equated to an annualize d cost of around $25 per low-bleed controller.

 2012 NSPS major pneumatic controller vendors were s urveyed for costs, emission rates, and any other pertinent information that would give an accurate p icture of the present industry (2011 TSD, p. 5-15).

 Instrument Air

7 EPA Air Pollution Control Cost Manual - Sixth Edit ion, (EPA 452/B-02-001).

###  System costs are dependent on size of compressor, p ower 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 f or Crude Oil and Natural Gas Production, Transmission, and D istribution. Background Technical Support Document for Proposed Standards. July 2011. EPA-453/R-11002. htt p://www.epa.gov/airquality/oilandgas/pdfs/20110728t sd.pdf

 2012 TSD: U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance f or Crude Oil and Natural Gas Production, Transmission, and D istribution. Background Supplemental Technical Supp ort Document for Proposed Standards. April 2012. Docket ID EPA-HQ-OAR-2010-0505-4550. http://www.epa.gov/airquality/oilandgas/pdfs/201204 18tsd.pdf

8 2011 TSD discusses the costs of instrument air req uirements for gas processing plants, which may be c onsidered an analogous requirement here.