***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

EO12866_Oil and Gas CTG 2060 ZA22 Guidance Document and Model Rule Draft 20150817

Control Techniques Guidelines for the Oil and 

Natural Gas Industry (Draft)
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EPA-453/P-15-001

August 2015

Control Techniques Guidelines for the Oil and Natural Gas 

Industry (Draft)

U.S. Environmental Protection Agency

Office of Air and Radiation

Office of Air Quality Planning and Standards

Sector Policies and Programs Division

Research Triangle Park, North Carolina
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

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DISCLAIMER

This report has been reviewed by EPA’s Office of Air Quality Planning and Standards 

and has been approved for publication. Mention of trade names or commercial products is not 

intended to constitute endorsement or recommendation for use. 
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TABLE OF CONTENTS

TABLE OF CONTENTS............................................................................................................................ v

1.0 INTRODUCTION .......................................................................................................................... 1-1

2.0 BACKGROUND AND OVERVIEW ............................................................................................ 2-1

2.1 History of Federal Actions that Regulate VOC Emissions in the Oil and Natural Gas 

Industry........................................................................................................................... 2-1

2.2 State and Local Regulations........................................................................................... 2-2

2.3 Development of this Guideline....................................................................................... 2-4

3.0 OVERVIEW OF THE OIL AND NATURAL GAS INDUSTRY AND SOURCES 

SELECTED FOR RACT RECOMMENDATIONS ...................................................................... 3-1

3.1 Overview of the Oil and Natural Gas Industry............................................................... 3-1

3.2 Sources Selected For RACT Recommendations............................................................ 3-5

4.0 STORAGE VESSELS .................................................................................................................... 4-1

4.1 Applicability................................................................................................................... 4-1

4.2 Process Description and Emission Sources.................................................................... 4-1

4.2.1 Process Description................................................................................................. 4-1

4.2.2 Emissions Data........................................................................................................ 4-2

4.3 Available Controls and Regulatory Approaches............................................................ 4-6

4.3.1 Available VOC Emission Control Options............................................................. 4-6

4.3.2 Existing Federal, State and Local Regulations..................................................... 4-17

4.4 Recommended RACT Level of Control....................................................................... 4-20

4.5 Factors to Consider in Developing Storage Vessel Compliance Procedures............... 4-22

4.5.1 Compliance Recommendations When Using a Control Device ........................... 4-22

5.0 COMPRESSORS............................................................................................................................ 5-1

5.1 Applicability................................................................................................................... 5-1

5.2 Process Description and Emission Sources.................................................................... 5-1

5.2.1 Process Description................................................................................................. 5-1

5.2.2 Emissions Data........................................................................................................ 5-5

5.3 Available Controls and Regulatory Approaches............................................................ 5-8

5.3.1 Available VOC Emission Control Options............................................................. 5-8

5.3.2 Existing Federal, State and Local Regulations..................................................... 5-23

5.4 Recommended RACT Level of Control....................................................................... 5-24

5.5 Factors to Consider in Developing Compressor Compliance Procedures ................... 5-26
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5.5.1 Reciprocating Compressor Compliance Recommendations................................. 5-26

5.5.2 Centrifugal Compressor Equipped with a Wet Seal Recommendations .............. 5-27

5.5.3 Recommendations for Cover Design.................................................................... 5-27

5.5.4 Recommendations for Closed Vent Systems........................................................ 5-28

6.0 PNEUMATIC CONTROLLERS ................................................................................................... 6-1

6.1 Applicability................................................................................................................... 6-1

6.2 Process Description and Emission Sources.................................................................... 6-2

6.2.1 Process Description................................................................................................. 6-2

6.2.2 Emissions Data........................................................................................................ 6-4

6.3 Available Controls and Regulatory Approaches............................................................ 6-8

6.3.1 Available VOC Emission Control Options............................................................. 6-8

6.3.2 Existing Federal, State and Local Regulations..................................................... 6-21

6.4 Recommended RACT Level of Control....................................................................... 6-22

6.4.1 Continuous Bleed Natural Gas-Driven Pneumatic Controllers Located at a Natural Gas 

Processing Plant.................................................................................................... 6-22

6.4.2 Continuous Bleed Natural Gas-Driven Pneumatic Controllers Located from the 

Wellhead to the Natural Gas Processing Plant or Point of Custody Transfer to an 

Oil Pipeline ........................................................................................................... 6-24

6.5 Factors to Consider in Developing Pneumatic Controller Compliance Procedures .... 6-26

6.5.1 Oil and Natural Gas Production (Individual Continuous Bleed Pneumatic Controller 

with a Natural Gas Bleed Rate Greater than 6 scf Located from the Wellhead to the 

Natural Gas Processing Plant or Point of Custody Transfer to an Oil Pipeline) .. 6-26

6.5.2 Natural Gas Processing Segment (Individual Continuous Bleed Natural Gas-Driven 

Pneumatic Controller Located at a Natural Gas Processing Plant)....................... 6-27

7.0 PNEUMATIC PUMPS ................................................................................................................... 7-1

7.1 Applicability................................................................................................................... 7-1

7.2 Process Description and Emission Sources.................................................................... 7-2

7.2.1 Process Description................................................................................................. 7-2

7.2.2 Emissions Data........................................................................................................ 7-4

7.3 Available Controls and Regulatory Approaches............................................................ 7-6

7.3.1 Available VOC Emission Control Options............................................................. 7-6

7.3.2 Existing Federal, State and Local Regulations..................................................... 7-17

7.4 Recommended RACT Level of Control....................................................................... 7-18

7.5 Factors to Consider in Developing Pneumatic Pump Compliance Procedures............ 7-20
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7.5.1 Oil and Natural Gas Production Segment Recommendations.............................. 7-20

7.5.2 Natural Gas Processing Segment Recommendations........................................... 7-20

8.0 EQUIPMENT LEAKS FROM NATURAL GAS PROCESSING PLANTS ................................ 8-1

8.1 Applicability................................................................................................................... 8-1

8.2 Process Description and Emission Sources.................................................................... 8-1

8.2.1 Process Description................................................................................................. 8-1

8.2.2 Equipment Leak Emission Data and Emission Factors.......................................... 8-2

8.3 Available Controls and Regulatory Approaches............................................................ 8-7

8.3.1 Available VOC Emission Control Options............................................................. 8-7

8.3.2 Existing Federal, State and Local Regulations..................................................... 8-13

8.4 Recommended RACT Level of Control for Equipment Leaks from Equipment at Natural 

Gas Processing Plants................................................................................................... 8-13

8.5 Factors to Consider in Developing Equipment Leak Compliance Procedures............ 8-14

9.0 FUGITIVE EMISSIONS FROM WELL SITES AND COMPRESSOR STATIONS .................. 9-1

9.1 Applicability................................................................................................................... 9-1

9.2 Fugitive Emissions Description and Data ...................................................................... 9-2

9.2.1 Fugitive Emissions Description .............................................................................. 9-2

9.2.2. Emission Data and Emission Factors...................................................................... 9-3

9.3 Available Controls and Regulatory Approaches.......................................................... 9-17

9.3.1 Available VOC Emission Control Options........................................................... 9-17

9.3.2 Existing Federal, State and Local Regulations..................................................... 9-31

9.4 Recommended RACT Level of Control....................................................................... 9-32

9.5 Factors to Consider in Developing Fugitive Emissions RACT Procedures................. 9-35

9.5.1 Monitoring Recommendations.............................................................................. 9-35

9.5.2 Repair Recommendations..................................................................................... 9-37

APPENDIX Recommended RACT Model Rule Language .............................................Appendix
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LIST OF TABLES

Table 3-1. Summary of the Oil and Natural Gas Industry Emission Sources and Recommended 

RACT Included in this Guideline ................................................................................................ 3-6

Table 4-1. Major Studies Reviewed for Consideration of Emissions and Activity Data ............ 4-3

Table 4-2. Average Oil and Condensate Production and Storage Vessel Emissions per Production 

Rate Bracket................................................................................................................................. 4-5

Table 4-3. Total Capital Investment and Total Annual Costs of a Vapor Recovery Unit System...

.................................................................................................................................................... 4-11

Table 4-4. Costs of Routing Emissions from an Existing Storage Vessel to a VRU ................ 4-11

Table 4-5. Total Capital Investment and Total Annual Costs of a Combustor.......................... 4-15

Table 4-6. Costs of Routing Emissions from an Existing Storage Vessel to a Combustion Device 

($/ton of VOC Reduced)............................................................................................................ 4-16

Table 4-7. Summary of Storage Vessel Regulations from Nine States..................................... 4-19

Table 5-1. Major Studies Reviewed for Emissions Data............................................................. 5-5

Table 5-2. Methane Emission Factors for Reciprocating and Centrifugal Compressors ............ 5-7

Table 5-3. Baseline Methane VOC Emission Estimates for Reciprocating and Centrifugal 

Compressorsa............................................................................................................................... 5-8

Table 5-4. Estimated Annual Reciprocating Compressor Emission Reductions from Increasing 

the Frequency of Rod Packing Replacement............................................................................. 5-12

Table 5-5. Cost of Control for Increasing the Frequency of Reciprocating Compressor Rod 

Packing Replacement................................................................................................................. 5-14

Table 5-6. Cost of Control of Replacing a Wet Seal Compressor with a Dry Seal Compressor......

.................................................................................................................................................... 5-19

Table 5-7. Estimated Annual Centrifugal Compressor VOC Emission Reductions for Routing 

Wet Seal Fluid Degassing System to a Process,........................................................................ 5-20

Table 5-8. VOC Cost of Control for Routing Wet Seal Fluid Degassing System to a Process........

.................................................................................................................................................... 5-21

Table 5-9. Estimated Annual VOC Emission Reductions for Routing Wet Seal Fluid Degassing 

System to a Combustion Device,............................................................................................... 5-22
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Table 5-10. Cost of Control for Routing Wet Seal Fluid Degassing System to a Combustion 

Device ........................................................................................................................................ 5-23

Table 6-1. Major Studies Reviewed for Consideration of Emissions and Activity Data ............ 6-4

Table 6-2. Average Emission Rates for High Bleed and Low Bleed Pneumatic Controllers in the 

Oil and Natural Gas Industrya...................................................................................................... 6-7

Table 6-3. Cost Projections for Representative Pneumatic Controllersa..................................... 6-9

Table 6-4. VOC Cost of Control for Replacing an Existing High Bleed Pneumatic Controller 

with a New Low Bleed Pneumatic Controller........................................................................... 6-10

Table 6-5. Compressor Power Requirements and Costs for Representative Instrument Air 

Systemsa..................................................................................................................................... 6-14

Table 6-6. Estimated Capital and Annual Costs of Representative Instrument Air Systems 

($2012)....................................................................................................................................... 6-16

Table 6-7. Cost of Control of Representative Instrument Air Systems in the Natural Gas 

Processing Segment ($2012)...................................................................................................... 6-16

Table 7-1. Major Studies Reviewed for Consideration of Emissions and Activity Data ............ 7-5

Table 7-2. Average Emission Estimates per Pneumatic Device.................................................. 7-6

Table 7-3. Cost of Compressor Replacement for Existing Instrument Air System................... 7-12

Table 7-4. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to an Existing 

Combustion Device.................................................................................................................... 7-14

Table 7-5. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to a New 

Combustion Device.................................................................................................................... 7-15

Table 7-6. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to an Existing 

VRU........................................................................................................................................... 7-16

Table 7-7. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to a New 

VRU........................................................................................................................................... 7-17

Table 8-1. Major Studies Reviewed for Consideration of Emissions and Activity Data ............ 8-2

Table 8-2. Equipment Counts for Natural Gas Processing Model Plant ..................................... 8-5

Table 8-3. Summary of Equipment Leak Frequency for Natural Gas......................................... 8-6

Table 8-4. Summary of VOC Equipment Leak Emission Factors for the Natural Gas Processing 

Model Plant.................................................................................................................................. 8-6

Table 8-5. Summary of the Gas Processing Model Plant VOC Cost of Control....................... 8-10
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Table 8-6. Summary of the Gas Processing Component VOC Cost of Control........................ 8-11

Table 8-7. Summary of the Natural Gas Processing Model Plant VOC Cost of Control for 

Optical Gas Imaging and Method 21 Monitoring...................................................................... 8-12

Table 9-1. Major Studies Reviewed for Emissions and Activity Data ........................................ 9-5

Table 9-2. Estimated Average Number of Wells per Site of New Well Completion in 2012..... 9-8

Table 9-3. Estimated Average Number of Wells per Two Acre Site of New Well Completion and 

Recompletion in 2012, by HPDI Basin and Type of Well (Oil or Natural Gas, Hydraulically

Fractured or Not).......................................................................................................................... 9-9

Table 9-4. Average Component Count for Natural Gas Well Site Model Plant........................ 9-12

Table 9-5. Average Component Count for Oil Well Site Model Plant...................................... 9-12

Table 9-6. Oil and Natural Gas Production Operations Average TOC Emission Factors......... 9-13

Table 9-7. Estimated Fugitive VOC Emissions for Natural Gas Production Model Plant........ 9-14

Table 9-8. Estimated Fugitive VOC Emissions for Oil Well Site Model Plant ........................ 9-14

Table 9-9. Average Component Count for the Oil and Natural Gas Production Gathering and 

Boosting Station Model Plant.................................................................................................... 9-16

Table 9-10. Estimated Fugitive TOC and VOC Emissions for the Oil and Natural Gas Production 

Gathering and Boosting Station Model Plant ............................................................................ 9-17

Table 9-11. Summary of the Model Plant VOC Cost of Control for the Annual OGI Monitoring 

Option ........................................................................................................................................ 9-22

Table 9-12. Summary of the Model Plant VOC Cost of Control for the Semiannual OGI 

Monitoring Option ..................................................................................................................... 9-23

Table 9-13. Summary of the Model Plant VOC Cost of Control for the Quarterly OGI 

Monitoring Option ..................................................................................................................... 9-24

Table 9-14. Summary of the Model Plant VOC Cost of Control for the Annual...................... 9-28

Table 9-15. Summary of the Model Plant VOC Cost of Control for the Semiannual............... 9-29

Table 9-16. Summary of the Model Plant VOC Cost of Control for the Quarterly .................. 9-30
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LIST OF FIGURES 

Figure 3-1. Oil and Natural Gas Industry Operations.................................................................. 3-4

Figure 4-1. Conventional Vapor Recovery System..................................................................... 4-8

Figure 4-2. Schematic of a Typical Enclosed Combustion System........................................... 4-13

Figure 4-3. Basic Schematic of a Thermal Oxidizer.................................................................. 4-14

Figure 5-1. Typical Reciprocating Compressor Rod Packing System Diagram ......................... 5-2

Figure 5-2. Typical Centrifugal Compressor Wet Seal ............................................................... 5-3

Figure 5-3. Typical Centrifugal Compressor Tandem Dry Seal.................................................. 5-4

Figure 6-1. Natural Gas Pneumatic Control System.................................................................. 6-13

Figure 6-2. Compressed Instrument Air Control System .......................................................... 6-14
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ACRONYMS AND ABBREVIATIONS

Acronyms/Abbreviations Description

ACA Air Compliance Advisor

ANGA America's Natural Gas Alliance 

APCD Air Pollution Control District 

APEN Air Pollutant Emission Notice

API American Petroleum Institute 

AQMD Air Quality Management District

ARCADIS a global consulting firm 

bbl/day barrels per day

BMP best management practice

BACT best available control technology

BOE/day barrels of oil equivalent per day

BSER best system of emission reduction

BTEX benzene, toluene, ethylbenzene and xylenes

Btu British thermal unit 

Btu/scf British thermal unit per standard cubic feet 

CAA Clean Air Act

CAPP Canadian Association of Petroleum Producer’s 

CE indices Chemical Engineering's index

CETAC-WEST Canadian Environmental Technology Advancement CorporationWEST

Cfm cubic foot per minute

CFR Code of Federal Regulations

CH4 Methane

CL Report Carbon Limit Report

CMSA Consolidated Metropolitan Statistical Area

CO carbon monoxide 

CO$T-AIR a group of spreadsheet programs used to cover 12 control devices and

one category of auxiliary equipment (ductwork)

CO2 carbon dioxide

CTG control techniques guidelines 

E&P Tanks Program is a personal computer-based software designed to use site-specific 

information to predict emission from petroleum production storage 

tanks

EIA Economic Impact Analysis 

ERG Eastern Research Group 

EVRU ejector vapor recovery units 

FIP Federal Implementation Plan 
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Acronyms/Abbreviations Description

FR Federal Register

FRED Federal Reserve Economic Data 

gal/yr gallon per year

GDP gross domestic product

GHG greenhouse gas

G gram

GRI Gas Research Institute 

H2S hydrogen sulfide 

HAP hazardous air pollutants

HFC Hydrofluorocarbon

HON Hazardous Organic NESHAP 

HPDI database provides production data and web-enabled analytical software tools 

for a wide range of oil and gas related customers 

ICF International a firm that provides professional services and technology solutions in 

strategy and policy analysis, program management, project 

evaluation, and other services

Inj/With injection/withdrawal components 

IR infrared 

kg/hr/comp kilogram per hour per component

kg/hr/source kilogram per hour per source

kg/MMBtu kilogram per million Btu

kPa kilopascals 

kW Kilowatt

LAER lowest achievable emission rate

lb/MMBtu pounds per million Btu

LDAR leak detection and repair

LLC liquid level controller

Mcf thousand cubic feet

MMcf/year million cubic feet per year 

MSA Metropolitan Statistical Area 

Mscf/cyl thousand standard cubic feet per cylinder 

Mscf/yr/component thousand standard cubic feet per year per component

NA Nonattainment

NESHAP National Emission Standards for Hazardous Air Pollutants 

NGL natural gas liquids

NOx nitrogen oxide

NSPS New Source Performance Standards 

NSR New Source Review

O&M operations & maintenance 

OAQPS Office of Air Quality Planning and Standards
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Acronyms/Abbreviations Description

OCCM OAQPS Control Cost Manual 

OEL open-ended lines

OGI optical gas imaging 

OTR Ozone Transport Region 

OVA organic vapor analyzer 

PC pressure controller

PG&E Pacific Gas & Electric 

PM particulate matter

PNAS Proceedings of the National Academy of Sciences 

ppm parts per million 

Ppmv parts per million by volume 

PRD pressure relief devices

PRV pressure relief valve 

PSD prevention of significant deterioration 

Psi pounds per square inch

Psig pounds per square inch gauge 

PTE potential to emit

RACT reasonably available control technology

RBLC RACT/BACT/LAER Clearinghouse

Scf standard cubic feet

scfh-cylinder standard cubic feet per hour-cylinder

Scfm standard cubic feet per minute

Scfh standard cubic feet per hour 

SIP State Implementation Plan

SO2 sulfur dioxide 

THC total hydrocarbons

TOC total organic compounds 

Tpy tons per year

TSD technical support document

TVA toxic vapor analyzer 

U.S. United States 

U.S. EIA U.S. Energy Information Administration 

U.S. EPA U.S. Environmental Protection Agency

VOC volatile organic compound

VRU vapor recovery unit 

μg/m3 micrograms per cubic meter
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1-1

Introduction

1.0 INTRODUCTION

Section 172(c)(1) of the Clean Air Act (CAA) provides that state implementation plans

(SIPs) for nonattainment areas must include “reasonably available control measures” including 

“reasonably available control technology” (RACT), for existing sources of emissions. CAA 

Section 182(b)(2)(A) provides that for moderate ozone nonattainment areas, states must revise 

their SIPs to include RACT for each category of volatile organic compound (VOC) sources 

covered by control techniques guidelines (CTG) document issued between November 15, 1990,

and the date of attainment. Section 182(c) through (e) applies this requirement to States with 

ozone nonattainment areas classified as serious, severe and extreme. CAA Section 184(b) 

requires that states in ozone transport regions (OTRs) must revise their SIPs to implement RACT 

with respect to all sources of VOC in the state covered by a CTG issued before or after 

November 15, 1990. CAA Section 184 (a) establishes a single ozone transport region comprised 

of the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New 

Jersey, New York, Pennsylvania, Rhode Island, Vermont and the Consolidated Metropolitan 

Statistical Area (CMSA) that includes the District of Columbia.

The U.S. Environmental Protection Agency (EPA) defines RACT as “the lowest 

emission limitation that a particular source is capable of meeting by the application of control 

technology that is reasonably available considering technological and economic feasibility.” 44 

FR 53761 (September 17, 1979). 

This guideline is intended to provide state, local and tribal air agencies (hereafter, air 

agencies) with information to assist them in determining RACT for reducing VOC emissions

from select oil and natural gas industry emission sources. In developing this guideline, the EPA, 

among other things, evaluated the sources of VOC emissions in the oil and natural gas industry

and the available control approaches for addressing these emissions, including the costs of such 

approaches. Based on available information and data, the EPA provides recommendations for 

RACT for select oil and natural gas industry emission sources. Air agencies can use the 

recommendations in this guideline to inform their own determination as to what constitutes 

RACT for VOC for the oil and natural gas industry emission sources presented in this document 

in their particular nonattainment areas. The information contained in this document is provided 

only as guidance. This guidance does not change, or substitute for, requirements specified in 
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1-2

Introduction

applicable sections of the CAA or the EPA’s regulations; nor is it a regulation itself. This 

document does not impose any requirements on facilities in the oil and natural gas industry. It 

provides only recommendations for air agencies to consider in determining RACT. Air agencies 

are free to implement other technically-sound approaches that are consistent with the CAA and 

the EPA’s implementing regulations.

The recommendations contained in this guideline are based on data and information 

currently available to the EPA. These general recommendations may not apply to a particular 

situation based upon the circumstances of a specific source. Regardless of whether an air agency

chooses to implement the recommendations contained herein through their rules, or to issue rules 

that adopt different approaches for RACT for VOC from oil and natural gas industry sources, air 

agencies must submit their RACT rules to the EPA for review and approval as part of the SIP 

process. The EPA will evaluate the rules and determine, through notice and comment rulemaking 

in the SIP review process, whether the submitted rules meet the RACT requirements of the CAA 

and the EPA’s regulations. To the extent an air agency adopts any of the recommendations in 

this guidance into its RACT rules, interested parties can raise questions and objections about the 

substance of this guidance and the appropriateness of the application of this guidance to a 

particular situation during the development of these rules and the EPA’s SIP review process.

Section 182(b)(2) of the CAA requires that a CTG issued between November 15, 1990, 

and the date of attainment include the date by which states subject to CAA section 182(b) must 

submit SIP revisions in response to the CTG. Accordingly, EPA is providing a 2 year period, 

from issuance of the final CTG, for the required submittal. 
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2-1

Background and Overview

2.0 BACKGROUND AND OVERVIEW

There have been several federal and state actions to reduce VOC emissions from certain 

emission sources in the oil and natural gas industry. A summary of these actions is provided 

below.

2.1 History of Federal Actions that Regulate VOC Emissions in the Oil and 

Natural Gas Industry

In 1979, the EPA listed crude oil and natural gas production on its priority list of source 

categories for promulgation of NSPS (44 FR 49222, August 21, 1979). Since the 1979 listing, 

the EPA has promulgated performance standards to regulate VOC emissions from production, 

processing, transmission and storage and sulfur dioxide (SO2) emissions from natural gas 

processing emission sources. On June 24, 1985 (50 FR 26122), the EPA promulgated an NSPS 

for natural gas processing plants that addressed VOC emissions from leaking components (40 

CFR part 60, subpart KKK). On October 1, 1985 (50 FR 40158), a second NSPS was 

promulgated for natural gas processing plants that regulated SO2emissions (40 CFR part 60, 

subpart LLL). On August 16, 2012 (77 FR 49490), the EPA finalized its review of NSPS 

standards for the listed oil and natural gas source category and revised the NSPS for VOC from 

leaking components at natural gas processing plants and the NSPS for SO2emissions from 

natural gas processing plants. At that time, the EPA also established standards for certain oil and 

natural gas emission sources not covered by the existing standards. In addition to the emission 

sources that were covered previously, the EPA established new standards to regulate VOC 

emissions from hydraulically fractured gas wells, centrifugal compressors, reciprocating 

compressors, pneumatic controllers and storage vessels. In 2013 (78 FR 58416) and 2014 (79 FR 

79018), the EPA amended the standards set in 2012 in order to improve implementation of the 

standards. In 2015, the EPA proposed new standards to regulate methane and VOC emissions 

across the oil and natural gas source category. Specifically, the EPA proposed both methane and 

VOC standards for several emission sources not currently covered by the NSPS (i.e., 

hydraulically fractured oil well completions, pneumatic pumps, and fugitive emissions from well 

sites and compressor stations). In addition, the EPA proposed methane standards for certain 

emission sources that are currently regulated for only VOC (i.e., hydraulically fractured gas well 
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2-2

Background and Overview

completions, centrifugal compressors, reciprocating compressors, pneumatic controllers, storage 

vessels and equipment leaks at natural gas processing plants). With respect to certain equipment 

that are used across the industry, the current NSPS regulates only a subset of these equipment 

(pneumatic controllers, centrifugal compressors, reciprocating compressors). The proposed 

amendents would establish methane standards for these equipment and extend the current VOC 

standards to unregulated equipment. Although not regulated under the oil and natural gas NSPS, 

internal combustion and combustion turbines used in the oil and natural gas industry are covered 

under separate NSPS specific to engines and turbines.

In addition to NSPS issued to regulate VOC emissions from the oil and gas industry, the 

EPA also published a CTG that recommended the control of VOC emissions from equipment 

leaks from natural gas processing plants in 1983 (1983 CTG).1This CTG is the only CTG issued 

since 1983 for the oil and natural gas industry.

2.2 State and Local Regulations

Several states regulate VOC emissions from storage vessels in the oil and natural gas

industry. There are also a few states (e.g., Colorado, Wyoming and Montana) that have 

established specific permitting requirements or regulations that control VOC emissions from 

other emission sources in the oil and natural gas industry (e.g., compressors, pneumatics, fugitive 

emission components):

(1) The Colorado Department of Public Health and Environment, Air Quality Control 

Commission has developed emission regulations 3, 6 and 7 that apply to oil and natural 

gas industry emission sources in Colorado. 

(https://www.colorado.gov/pacific/cdphe/summary-oil-and-gas-emissions-requirements)

(2) Montana requires oil and gas well facilities to control emissions from the time the well is 

completed until the source is registered or permitted (Registration of Air Contaminant 

Sources Rule, Rule 17.8.1711, Oil or Gas Well Facilities Emission Control 

Requirements). (http://www.mtrules.org/gateway/ruleno.asp?RN=17%2E8%2E1711.)

 

1 U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, 

NC, 27711. Guideline Series. Control of Volatile Organic Compound Equipment Leaks from Natural Gas/Gasoline 

Processing Plants. December 1983. EPA-450/3-83-007
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2-3

Background and Overview

(3) The Wyoming Department of Environmental Quality limits VOC emissions from existing 

sources in ozone nonattainment areas and has issued specific permitting guidance that 

apply to oil and natural gas facilities. (Chapter 6, Section 2 Permitting Guidance, last 

revised in September 2013). (http://www.oilandgasbmps.ort/laws/wyoming_law.php.) 

In some states, general permits have been developed for oil and natural gas facilities. 

General permits are permits where all the terms and conditions of the permit are developed for a 

given industry and authorize the construction, modification, and/or operation of facilities that 

meet the terms and conditions. For example, West Virginia, Ohio and Pennsylvania have 

developed General Air Permits. The Pennsylvania Department of Environmental Protection has 

issued a General Permit, General Plan Approval and Permit Exemption 38 for natural gas 

dispensing facilities and oil and gas exploration, development and production operations. 

Pennsylvania also applies conditions on flaring of emissions. Under the Permit 38 exemptions, 

there are criteria set out for the oil and natural gas industry that include unconditionally exempt 

and conditionally exempt criteria. Unconditionally exempt operations/equipment include 

conventional wells, conventional wellheads and associated equipment, well-drilling, completion 

and work-over activities, and non-road engines. Unconventional wells, wellheads and associated 

equipment (including equipment components, storage vessels) are conditionally exempt. 

Conditions include compliance with 40 CFR part 60, subpart OOOO and Pennsylvania’s General 

Permit 5 (GP-5) and a demonstration that the combined VOC emissions from all sources at a 

facility are less than 2.7 tons per year (tpy) on a 12-month rolling basis. For oil and natural gas 

facilities that do not meet these conditions, a case-by-case plan approval is required.2

There may also be local permit requirements for control of VOC emissions from existing 

sources of VOC emissions in the oil and natural gas industry, such as those required by the Bay

Area Air Quality Management District (BAAQMD) for pneumatic controllers. The BAAQMD

requires that a permit to operate applicant provide the number of high bleed and low bleed

pneumatic devices in their permit application. Facilities that use high bleed devices might be 

required to provide device-specific bleed rates and supporting documentation for each high bleed

device. In cases where emissions are high from high bleed devices, BAAQMD might require that 

 

2

Pennsylvania Department of Environmental Protection. Comparison of Air Emission Standards for the Oil & 

Natural Gas Industry (Well Pad Operations, Natural Gas Compressor Stations, and Natural Gas Processing 

Facilities). May 23, 2014.
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Background and Overview

the facility conduct fugitive monitoring and/or control requirements under conditions of their 

permit to operate3on a case-by-case basis.

We conducted a search of the EPA’s RACT/BACT/LAER Clearinghouse (RBLC) and 

identified several draft and final permits that covered some of the sources evaluated for RACT in 

this guideline. The controls specified in these permits are similar to the control options evaluated 

in this guideline.4

We considered these existing state and local requirements limiting VOC emissions from 

the oil and natural gas industry in preparing this guideline.

2.3 Development of this Guideline

As discussed in section 2.1 of this chapter, the 2012 NSPS established VOC emission 

standards for new and modified sources. This guideline addresses existing sources of VOC 

emissions and provides recommendations for RACT for the oil and natural gas industry. We 

developed our RACT recommendations after reviewing the 1983 CTG, the oil and natural gas 

NSPS, existing state and local VOC emission reduction approaches, and information on costs, 

emissions and available VOC emission control technologies. In April 2014, the EPA released 

five technical white papers on potentially significant sources of emissions in the oil and natural 

gas industry. The white papers focused on technical issues covering emissions and mitigation 

techniques that target methane and VOC. We consulted the white papers, along with the input we 

received from the peer reviewers and the public, when evaluating and recommending a RACT 

level of control.

This guideline evaluated potential RACT control options for emission sources that are 

regulated or proposed to be regulated under the oil and natural gas NSPS. This guideline did not 

evaluate hydraulically fractured oil and natural gas well completions performed on existing wells 

because these operations are considered modifications and, therefore, subject to the NSPS. 

Several of the technical support documents (TSDs) prepared in support of the NSPS 

actions for the oil and natural gas industry include data and analyses considered in developing 

RACT recommendations in this guideline. To the extent that the data and analyses are also 

 

3 Cheng, Jimmy. Permit Handbook. Chapter 3.5 Natural Gas Facilities and Crude Oil Facilities. Bay Area Air 

Quality Management District. September 16, 2013.

4 RACT/BACT/LAER Clearinghouse website: http://cfpub.epa.gov/RBLC/
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Background and Overview

relevant to control options for existing sources, they are referred to throughout this guidance 

document as follows:

(1) The TSD for the 2011 NSPS proposal, published in July, 2011 is referred to as the “2011 

NSPS TSD”.

5

(2) The supplemental TSD for the 2012 final NSPS standards, published in April, 2012 is

referred to as the “2012 NSPS TSD” or “2012 NSPS STSD”

6

(3) The TSD for the 2015 proposed NSPS standards is referred to as the “2015 NSPS TSD”.7

Additionally, emissions information and counts for various emission sources were 

summarized from facility-level data submitted to the Greenhouse Gas Reporting Program 

(GHGRP)8and data used to calculate national emissions in the Inventory of U.S. Greenhouse 

Gas Emissions and Sinks.9The published data from 2013 was used for various portions of the 

analysis. For the purposes of this document these data sources are referred to as the “GHGRP”

and the “GHG Inventory”.

Most of the VOC emission estimates presented in this document are based on methane 

emissions because the available emissions information we had for the evaluated sources are for 

methane. We calculated VOC emissions using ratios of methane to VOC in the gas for the 

different segments of the industry. These ratios, and the procedures used to calculate them, are 

documented in a memorandum characterizing gas composition developed during the NSPS 

process. 11 Herein, we refer to this memorandum as the “2011 Gas Composition Memorandum’.

Because methane emissions are the basis for most of our VOC emissions estimates, in several 

 

5 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution – Background Technical Support Document for Proposed 

Standards. July 2011. EPA-453/R-11002.

6 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document 

for the Final New Source Performance Standards. April 2012. Docket ID No. EPA-HQ-OAR-2010-0505-4550.

7 U.S. Environmental Protection Agency. Oil and Natural Gas Source Category: Standards of Performance for 

Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Technical Support Document 

for the Proposed Amendments to the New Source Performance Standards. August 2015.

8 U.S. Environmental Protection Agency. Mandatory Reporting of Greenhouse Gases from Petroleum and Natural 

Gas Systems – Subpart W. Washington, DC. November 2010. (Reported Data: 

http://www.epa.gov/ghgreporting/reporters/subpart/w-reported.html)

9 U.S. EPA. Inventory of U.S. Greenhouse Gas Inventory and Sinks. 1990 - 2012. Available at 

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/archive.html

11 Memorandum to Bruce Moore, U.S. EPA from Heather Brown, EC/R. Composition of Natural Gas for Use in the 

Oil and Natural Gas Sector Rulemaking. July 2011. Docket ID No. EPA-HQ-OAR-2010-0505-0084.
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Background and Overview

instances where we provide VOC emissions per source/model plant, we also provide the methane 

emissions that are the basis for our VOC emissions estimates.

(4)

(5)

(6)

We have divided the remainder of this document into seven chapters and an appendix.

Chapter three describes the oil and natural gas industry and a summary of our RACT 

recommendations presented in this guideline. Chapters four through nine describe the oil and 

natural gas emission sources that we evaluated for our RACT recommendations (i.e., storage 

vessels, compressors, pneumatic controllers, pneumatic pumps, equipment component leaks 

from natural gas processing plants and fugitive emissions from well sites and compressor

stations), available control and regulatory approaches (including existing federal, state and local 

requirements) and the potential emission reductions and costs associated with available control 

and regulatory approaches for a given emission source. The appendix provides example model 

rule language that can be used by states if they choose to adopt the recommended RACT level of 

control presented in this document.
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3-1

Overview of the Oil and Natural Gas Industry and Sources 

3.0 OVERVIEW OF THE OIL AND NATURAL GAS INDUSTRY AND 

SOURCES SELECTED FOR RACT RECOMMENDATIONS

Section 3.1 presents an overall description of the oil and natural gas industry and section

3.2 presents the VOC emission sources for which we are recommending RACT within the oil 

and natural gas industry.

3.1 Overview of the Oil and Natural Gas Industry

The oil and natural gas industry includes oil and natural gas operations involved in the 

extraction and production of crude oil and natural gas, as well as the processing, transmission 

and distribution of natural gas. For oil, the industry includes all operations from the well to the 

point of custody transfer at a petroleum refinery. For natural gas, the industry includes all 

operations from the well to the customer. For purposes of this document, the oil and natural gas

operations are separated into four segments: (1) oil and natural gas production, (2) natural gas 

processing, (3) natural gas transmission and storage and (4) natural gas distribution. We briefly

discuss each of these segments below.

For purposes of this guideline, oil and natural gas production includes onshore 

operations. Production operations include the wells and all related processes used in the 

extraction, production, recovery, lifting, stabilization and separation or treating of oil and/or 

natural gas (including condensate). Production components may include, but are not limited to, 

wells and related casing head, tubing head and “Christmas tree” piping, as well as pumps, 

compressors, heater treaters, separators, storage vessels, pneumatic devices and dehydrators. 

Production operations also include well drilling, completion and recompletion processes, which 

include all the portable non-self-propelled apparatus associated with those operations. Production 

sites include the “pads” where the wells are located and stand-alone sites where oil, condensate, 

produced water and natural gas from several wells may be separated, stored and treated. The 

production segment also includes the low pressure, small diameter, gathering pipelines and 

related components that collect and transport the oil, natural gas and other materials and wastes 

from the wells to the refineries or natural gas processing plants. These are also referred to as 

“flow lines” and “sales lines.”
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Overview of the Oil and Natural Gas Industry and Sources 

There are two basic types of wells: Oil wells and natural gas wells. Oil wells can have 

“associated” natural gas that is separated and processed or the crude oil can be the only product 

processed. Once the crude oil is separated from water and other impurities, it is essentially ready

to be transported to the refinery via truck, railcar or pipeline. The petroleum refining industry is 

considered separately from the oil and natural gas industry. Therefore, at the point of custody

transfer at the refinery, the oil leaves the oil and natural gas industry and enters the petroleum 

refining industry.

Gas from natural gas wells is primarily made up of methane. However, whether natural 

gas is associated natural gas from oil wells, or non-associated natural gas from natural gas or 

condensate wells, it commonly exists in mixtures with other hydrocarbons. These hydrocarbons 

are often referred to as natural gas liquids (NGL). They are sold separately and have a variety of 

uses. The raw natural gas often contains water vapor, hydrogen sulfide (H2S), carbon dioxide 

(CO2), helium, nitrogen and other compounds. 

Natural gas processing consists of separating certain hydrocarbons and fluids from the 

natural gas to produce “pipeline quality” dry natural gas. While some of the processing can be 

accomplished in the production segment, the complete processing of natural gas takes place in 

the natural gas processing segment. Natural gas processing operations separate and recover NGL 

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

components performing one or more of the following processes: oil and condensate separation, 

water removal, separation of natural gas liquids, sulfur and CO2 removal, fractionation of NGL

and other processes, such as the capture of CO2 separated from natural gas streams for delivery

outside the facility. 

The pipeline quality natural gas leaves the processing segment and enters the 

transmission and storage segment. Pipelines in the natural gas transmission and storage segment 

can be interstate pipelines that carry natural gas across state boundaries or intrastate pipelines 

that transport the gas within a single state. While interstate pipelines may be of a larger diameter 

and operated at a higher pressure, the basic components are the same. To ensure that the natural 

gas flowing through any pipeline remains pressurized, compression of the gas is required 

periodically along the pipeline. This is accomplished by compressor stations usually placed at 

intervals between 40 and 100 miles along the pipeline. At a compressor station, the natural gas 
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3-3

Overview of the Oil and Natural Gas Industry and Sources 

enters the station, where it is compressed by reciprocating or centrifugal compressors.

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

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

consumer. In the production segment, compressors are used at the wellhead to compress gas for 

fluids removal and pressure equalization with gathering equipment systems. However, the 

primary use of compressors is in the natural gas processing, transmission and storage 

(particularly underground storage) segments of the industry.

In addition to the pipelines and compressor stations, the natural gas transmission and 

storage segment includes aboveground and underground storage facilities. Underground natural 

gas storage includes subsurface storage, which typically consists of depleted natural gas or oil 

reservoirs and salt dome caverns used for storing natural gas. One purpose of this storage is for 

load balancing (equalizing the receipt and delivery of natural gas). At an underground storage 

site, there are typically other processes, including compression, dehydration and flow 

measurement.

The distribution segment is the final step in delivering natural gas to customers. The 

natural gas enters the distribution segment from delivery points located on interstate and 

intrastate transmission pipelines to business and household customers. Natural gas distribution 

systems consist of thousands of miles of piping, including mains and service pipelines to the 

customers. Distribution systems sometimes have compressor stations, although they are 

considerably smaller than transmission compressor stations.

Distribution systems include metering stations, which allow distribution companies to 

monitor the natural gas in the system. Essentially, these metering stations measure the flow of 

natural gas and allow distribution companies to track natural gas as it flows through the system.

Figure 3-1 presents a schematic of oil and natural gas sector operations.
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3-4

Overview of the Oil and Natural Gas Industry and Sources 

Figure 3-1. Oil and Natural Gas Sector Operations
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3-5

Overview of the Oil and Natural Gas Industry and Sources 

3.2 Sources Selected For RACT Recommendations 

This CTG covers select sources of VOC emissions in the onshore production and 

processing segments of the oil and natural gas industry (i.e., pneumatic controllers, pneumatic 

pumps, compressors, equipment leaks, fugitive emissions) and storage vessel VOC emissions in 

all segments (except distribution) of the oil and natural gas industry. These sources were selected 

for RACT recommendations because they are significant sources of VOC emissions. As 

mentioned in section 2.3, the VOC RACT recommendations contained in this document were 

made based on the review of the 1983 CTG, the oil and natural gas NSPS, existing state and 

local VOC emission reduction approaches, and information on emissions, available VOC

emission control technologies and costs obtained since issuance of these NSPS. 

In considering costs, we compared control options and estimated costs and emission 

impacts of multiple emission reduction options under consideration. Recommendations are 

presented in this guideline for the subset of existing sources in the oil and natural gas industry

where the application of controls is judged reasonable, given the availability of demonstrated 

control technologies, emission reductions that can be achieved and the cost of control. 

Table 3-1 presents a summary of the oil and natural gas emission sources and 

recommended RACT included in this guideline.
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Overview of the Oil and Natural Gas Industry and Sources 

Table 3-1. Summary of the Oil and Natural Gas Industry Emission Sources and 

Recommended RACT Included in this Guideline

Emission Source Applicability RACT Recommendations

Storage Vessels Individual storage vessel. 95 percent reduction of VOC emissions 

from storage vessels with a potential to 

emit (PTE) greater than or equal to 6 tpy.

Pneumatic Controllers Individual continuous bleed, 

natural gas-driven pneumatic 

controller located at a natural gas 

processing plant.

Natural gas bleed rate of zero scfh 

(unless there are functional needs, 

including but not limited to response 

time, safety and positive actuation, 

requiring a bleed rate greater than zero

scfh).

Individual continuous bleed 

natural gas-driven pneumatic 

controller located from the 

wellhead to the natural gas 

processing plant or point of 

custody transfer to an oil 

pipeline.

Natural gas bleed rate less than or equal 

to 6 scfh (unless there are functional 

needs, including but not limited to 

response time, safety and positive 

actuation, requiring a bleed rate greater 

than 6 scfh). 

Pneumatic Pumps Individual natural gas-driven 

chemical/methanol and 

diaphragm pump located at a 

natural gas processing plant.

Zero natural gas emissions.

Individual natural gas-driven 

chemical/methanol and 

diaphragm pump at locations 

other than natural gas processing 

plants from the wellhead to the

point of custody transfer to the 

natural gas transmission and 

storage segment.

-If there is an existing control device at 

the location of the pneumatic pump, 

reduce VOC emissions from each gasdriven chemical/methanol and 

diaphragm pump at the location by 95 

percent or greater. 

- If there is no existing control device 

at the location of the pneumatic 

pump, submit a certification that there is 

no device.

Compressors 

(Centrifugal and 

Reciprocating)

Individual reciprocating 

compressor located between the 

wellhead and point of custody 

transfer to the natural gas 

transmission and storage 

segment. 

Reduce VOC emissions by replacing 

reciprocating compressor rod packing 

after 26,000 hours of operation or 36 

months since the most recent rod packing 

replacement. Alternatively, route rod 

packing emissions to a process through a 

closed vent system under negative 

pressure. 
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Overview of the Oil and Natural Gas Industry and Sources 

Emission Source Applicability RACT Recommendations

Individual reciprocating 

compressor located at a well site, 

or an adjacent well site and 

servicing more than one well site 

RACT would not apply.

Individual centrifugal 

compressor using wet seals that 

is located between the wellhead 

and point of custody transfer to 

the natural gas transmission and 

storage segment. 

Reduce VOC emissions from each 

centrifugal compressor wet seal fluid 

gassing system by 95 percent or greater.

Individual centrifugal 

compressor using wet seals 

located at a well site, or an 

adjacent well site and servicing 

more than one well site. 

RACT would not apply.

Individual centrifugal

compressor using dry seals.

RACT would not apply.

Equipment Leaks Equipment components in VOC 

service located at a natural gas 

processing plant.

Implement the 40 CFR part 60, subpart 

VVa leak detection and repair (LDAR)

program for natural gas processing plants 

constructed or modified on or before 

August 23, 2011.

Fugitive Emissions Individual well site with wells 

that produce, on average, greater 

than 15 barrel equivalents per 

day per well.

Implement a semiannual optical gas 

imaging (OGI) monitoring and repair 

program.

Individual compressor station 

located from the wellhead to the 

point of custody transfer to the 

natural gas transmission and 

storage segment or point of 

custody transfer to an oil 

pipeline.

Implement an OGI monitoring and repair 

program.
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4-1

Storage Vessels 

4.0 STORAGE VESSELS

Storage vessels are significant sources of VOC emissions in the oil and natural gas

industry. This chapter provides a description of the types of storage vessels present in the oil and 

natural gas industry, and provides VOC emission estimates for storage vessels, in terms of mass 

of emissions per throughput, for both crude oil and condensate storage vessels. This chapter also 

presents control techniques used to reduce VOC emissions from storage vessels, along with their 

costs and potential emission reductions. Finally, this chapter provides a discussion of our 

recommended RACT for storage vessels. 

4.1 Applicability

For purposes of this guideline, the emissions and emission controls discussed herein 

would apply to a tank or other vessel in the oil and natural gas industry that contains an 

accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water, and 

that is constructed primarily of non-earthen materials (such as wood, concrete, steel, fiberglass, 

or plastic) that provide structural support. The emissions and emission controls discussed herein 

would not apply to the following vessels:

(1) Vessels that are skid-mounted or permanently attached to something that is mobile (such 

as trucks, railcars, barges or ships), and are intended to be located at a site for less than 

180 consecutive days.

(2) Process vessels such as surge control vessels, bottoms receivers or knockout vessels.

(3) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions 

to the atmosphere.

4.2 Process Description and Emission Sources

4.2.1 Process Description

Storage vessels in the oil and natural gas industry are used to hold a variety of liquids, 

including crude oil, condensates, produced water, etc. Underground crude oil contains many

lighter hydrocarbons in solution. When the oil is brought to the surface and processed, many of 

the dissolved lighter hydrocarbons (as well as water) are removed through a series of highpressure and low-pressure separators. Crude oil under high pressure conditions is passed through 
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Storage Vessels 

either a two-phase separator (where the associated gas is removed and any oil and water remain 

together) or a three-phase separator (where the associated gas is removed and the oil and water 

are also separated). At the separator, low pressure gas is physically separated from the high 

pressure oil. The remaining low pressure oil is then directed to a storage vessel where it is stored 

for a period of time before being transported off-site. Much of the remaining hydrocarbon gases

in the oil are released from the oil as vapors in the storage vessels. Storage vessels are typically 

installed with similar or identical vessels in a group, referred to in the industry as a tank battery.

Emissions of the hydrocarbons from storage vessels are a function of working, breathing 

(or standing), and flash losses. Working losses occur when vapors are displaced due to the 

emptying and filling of storage vessels. Breathing losses are the release of gas associated with 

temperature fluctuations and other equilibrium effects. Flash losses occur when a liquid with 

entrained gases is transferred from a vessel with higher pressure to a vessel with lower pressure, 

thus allowing entrained gases or a portion of the liquid to vaporize or flash. In the oil and natural 

gas industry, flashing losses occur when crude oils or condensates flow into a storage vessel

from a processing vessel operated at a higher pressure. Typically, the larger the pressure drop, 

the more flash emissions will occur in the storage vessel. Temperature of the liquid may also 

influence the amount of flash emissions. The volume of gas vapor emitted from a storage vessel 

depends on many factors. Lighter crude oils flash more hydrocarbons than heavier crude oils. In 

storage vessels where the oil is frequently cycled and the overall throughput is high, working 

losses are higher. Additionally, the operating temperature and pressure of oil in the separator 

dumping into the storage vessel will affect the volume of flashed gases coming out of the oil.

The composition of the vapors from storage vessels varies, and the largest component is 

methane, but also may include ethane, butane, propane, and HAP such as BTEX, and n-hexane.

4.2.2 Emissions Data

4.2.2.1 Summary of Major Studies and Emissions

Given the potentially significant emissions from storage vessels, there are numerous 

studies and reports available that estimate storage vessel emissions. We consulted several of 

these studies and reports to evaluate the emissions and emission reduction options for storage 

vessels. Table 4-1 presents a summary of the references for these reports, along with an 

indication of the type of information available in each reference.
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Storage Vessels 

Table 4-1. Major Studies Reviewed for Consideration of Emissions and Activity Dataa,b

Report Name Affiliation Year of 

Report

Activity 

Factors

Emissions 

Data

Control 

Options

VOC Emissions from Oil and 

Condensate Storage Tanks

Texas Environmental 

Research Consortium 2009 Regional X X

Upstream Oil and Gas Storage 

Tank Project Flash Emissions 

Models Evaluation – Final 

Report

Texas Commission on 

Environmental Quality 2009 Regional X

Initial Economics Impact 

Analysis for Proposed State 

Implementation Plan 

Revisions to the Air Quality 

Control Commission’s 

Regulation Number 7

Colorado Air Quality 

Control Commission 2008 NA X

E&P TANKS API National X

Inventory of U.S. Greenhouse 

Gas Emissions and Sinks EPA Annual National X

Greenhouse Gas Reporting 

Program (Annual Reporting: 

Current Data Available for 

2011-2013)C

EPA 2014 FacilityLevel X X

NA = Not Applicable 

a. U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas 

Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New Source 

Performance Standards. April 2012. EPA Docket ID No. EPA-HQ-OAR-2010-0505-4550.

b. U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas 

Production, Transmission, and Distribution - Technical Support. July 2011. EPA-453/R-11-002.

c. U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: 

Background Technical Support Document. Climate Change Division. Washington, DC. November 2014.

4.2.2.2 Representative Storage Vessel Baseline Emissions

Storage vessels vary in size and throughputs. In support of the 2013 NSPS, average

storage vessel emissions, in terms of mass of emissions per throughput, were developed for both 

crude oil and condensate storage vessels.

16 We also developed mass emissions per throughput 

estimates using the American Petroleum Institute’s (API’s) E&P Tanks program and more than 

 

16 Brown, Heather, EC/R Incorporated. Memorandum prepared for Bruce Moore, EPA/OAQPS/SPPD/FIG. Revised 

Analysis to Determine the Number of Storage Vessels Projected to be Subject to New Source Performance 

Standards for the Oil and Natural Gas Sector. 2013.
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Storage Vessels 

100 storage vessels across the country with varying characteristics.17 The VOC emissions per 

throughput estimates used for this analysis are:

(1) Uncontrolled VOC Emissions from Crude Oil Storage Vessels = 0.214 tpy VOC/barrel 

per day (bbl/day); and 

(2) Uncontrolled VOC Emissions from Condensate Storage Vessels = 2.09 tpy VOC/bbl/day. 

On a nationwide basis, there are a wide variety of storage vessel sizes, as well as rates of 

throughput for each tank. Emissions are directly related to the throughput of liquids for a given 

storage vessel; therefore, in support of the 2013 NSPS, we adopted production rate brackets 

developed by the U.S. Energy Information Administration (EIA) for our emission estimates. To 

estimate the emissions from an average storage vessel within each production rate bracket, we 

developed average production rates for each bracket. This average was calculated using the EIA 

published nationwide production per well per day for each production rate bracket from 2006 

through 2009. Table 4-2 presents the average oil production and condensate production in barrels 

per well per day. For this analysis, we considered the liquid produced (as reported by the EIA) 

from oil wells to be crude oil and from gas wells to be condensate. Table 4-2 presents the 

average VOC emissions for each storage vessel within each production rate bracket calculated by 

applying the average production rate (bbl/day) to the VOC emissions per throughput estimates

(tpy VOC/bbl/day).

 

17 American Petroleum Institute. Production Tank Emissions Model. E&P Tank Version 2.0. A Program for 

Estimating Emissions from Hydrocarbon Production Tanks. Software Number 4697. April 2000.
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Storage Vessels 

Table 4-2. Average Oil and Condensate Production and Storage Vessel Emissions per

Production Rate Bracket18

Production

Rate Bracket

(BOE/day)

a

Oil Wells Gas Wells

Average Oil

Production Rate

per Oil Well

(bbl/day)

b

Crude Oil

Storage Vessel

VOC Emissions

(tpy)

c

Average 

Condensate

Production Rate

per Gas Well

(bbl/day)

b

Condensate

Storage Vessel

VOC Emissions

(tpy)

c

0-1 0.385 0.083 0.0183 0.038

1-2 1.34 0.287 0.0802 0.168

2-4 2.66 0.570 0.152 0.318

4-6 4.45 0.953 0.274 0.573

6-8 6.22 1.33 0.394 0.825

8-10 8.08 1.73 0.499 1.04

10-12 9.83 2.11 0.655 1.37

12-15 12.1 2.59 0.733 1.53

15-20 15.4 3.31 1.00 2.10

20-25 19.9 4.27 1.59 3.32

25-30 24.3 5.22 1.84 3.85

30-40 30.5 6.54 2.55 5.33

40-50 39.2 8.41 3.63 7.59

50-100 61.6 13.2 5.60 11.7

100-200 120 25.6 12.1 25.4

200-400 238 51.0 23.8 49.8

400-800 456 97.7 44.1 92.3

800-1,600 914 196 67.9 142

1,600-3,200 1,692 363 148 311

3,200-6,400 3,353 719 234 490

6,400-12,800 6,825 1,464 891 1,864

> 12,800

d

0 0 0 0

Minor discrepancies may be due to rounding.

a. BOE=Barrels of Oil Equivalent

b. Oil and condensate production rates published by EIA. “US Total Distribution of Wells by Production Rate Bracket.”

http://www.eia.doe.gov/pub/oil_gas/petrosystem/us_table.html.

c. Oil storage vessel VOC emission factor = 0.214 tpy VOC/bbl/day. Condensate storage vessel VOC emission factor = 2.09

tpy/bbl/day.

d. There were no new oil and gas well completions in 2009 for this rate category. Therefore, average production rates were set

to zero.

 

18 Brown, Heather, EC/R Incorporated. Memorandum prepared for Bruce Moore, EPA/OAQPS/SPPD/FIG. Revised 

Analysis to Determine the Number of Storage Vessels Projected to be Subject to New Source Performance 

Standards for the Oil and Natural Gas Sector. 2013.
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Storage Vessels 

4.3 Available Controls and Regulatory Approaches

In analyzing available controls for storage vessels, we reviewed information obtained in 

support of the 2012 NSPS and the 2013 NSPS actions, control techniques identified in the 

Natural Gas STAR program, and existing state regulations that require control of VOC emissions 

from storage vessels in the oil and natural gas industry. Section 4.3.1 presents a discussion of the 

available VOC emission controls for storage vessels. Section 4.3.2 includes a summary of the 

federal, state and local regulatory approaches that control VOC emissions from crude oil and 

condensate storage vessels.

4.3.1 Available VOC Emission Control Options

The options generally used to limit the amount of VOC vented are to (1) route emissions 

from the storage vessel to any enclosed portion of a process where emissions are recycled, 

recovered, or reused in the process “route to a process”) (e.g., by installing a vapor recovery unit 

(VRU) that recovers vapors from the storage vessel); and (2) route emissions from the storage 

vessel to a combustor. One of the clear advantages the first option has over the second option is 

that it results in a cost savings associated with the recycled, recovered, and reused natural gas, 

rather than the loss and destruction of the natural gas by combustion. Combustion and partial 

combustion of organic pollutants also creates secondary pollutants including nitrogen oxides, 

carbon monoxide, sulfur oxides, carbon dioxide and smoke/particulates. These emission control 

methods are described below along with their emission reduction control effectiveness as they

apply to storage vessels in the industry and the potential costs associated with their installation 

and operation.

4.3.1.1 Routing Emissions to a Process via a Vapor Recovery Unit (VRU)

Description

One option for controlling storage vessel emissions is to route vapors from the storage 

vessels back to the inlet line of a separator, to a sales gas line, or to some other line carrying 

hydrocarbon fluids. Where a compressor is used to boost the recovered vapors into the line, this 

is often referred to as a VRU.19 Typically with a VRU, hydrocarbon vapors are drawn out of the 

 

19 American Petroleum Institute. Letter to Bruce Moore, SPPD/OAQPS/EPA from M. Todd, API. Re: Oil and 

Natural Gas Sector Consolidated Rulemaking. Docket ID No.EPA-HQ-OAR-2010-0505.
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storage vessel under low pressure and are piped to a separator, or suction scrubber, to collect any 

condensed liquids, which are usually recycled back to the storage vessel. Vapors from the 

separator flow through a compressor that provides the low-pressure suction for the VRU system

where the recovered hydrocarbons can be transported to various places, including a sales line 

and/or for use on-site. 

Types of VRUs include conventional VRUs and venturi ejector vapor recovery units 

(EVRUTM) or vapor jet systems.20 Decisions on the type of VRU to use are based on the 

applicability needs (e.g., an EVRUTM is recommended where there is a high pressure gas 

compressor with excess capacity and a vapor jet VRU is suggested where there is produced 

water, less than 75 million cubic feet (Mcf)/day gas and discharge pressures below 40 pounds per 

square inch gauge (psig). The reliability and integrity of the compressor and suction scrubber and 

integrity of the lines that connect the tank to the compressor will affect the effectiveness of the 

VRU system to collect and recycle vapors.21

A conventional VRU is equipped with a control pilot to shut down the compressor and 

permit the back flow of vapors into the tank in order to prevent the creation of a vacuum in the 

top of a tank when liquid is withdrawn and the liquid level drops. Vapors are then either sent to 

the pipeline for sale or used as on-site fuel. Figure 4.1 presents a diagram of a conventional VRU 

installed on a single crude oil storage vessel (multiple tank installations are also common).22

 

20 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Installing Vapor 

Recovery Units. Natural Gas STAR Program. Source Reduction Training to Interstate Oil and Gas Compact 

Commission Presentation. February 27, 2009.

21 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Installing Vapor 

Recovery Units on Storage Tanks. Natural Gas STAR Program. October 2006. 

http://www.epa.gov/gasstar/documents/ll_final_vap.pdf.

22 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Installing Vapor 

Recovery Units on Storage Tanks. Natural Gas Star Program. October 2006. 

http://www.epa.gov/gasstar/documents/ll_final_vap.pdf.
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Storage Vessels 

Figure 4-1. Conventional Vapor Recovery System

Control Effectiveness

VRUs have been shown to reduce VOC emissions from storage vessels by over 95

percent and some states require that a VRU used to control VOC emissions from crude oil and 

condensate storage vessels achieve a 98 percent reduction in VOC emissions.

23,24 VRUs do not 

generally operate 100 percent of the time due to maintenance and repair down time. For purposes 

of our analysis, we use 95 percent as the level of control that can consistently be achieved by the 

use of a VRU. A VRU recovers hydrocarbon vapors that potentially can be used as supplemental 

burner fuel, or the vapors can be condensed and collected as condensate that can be sold. If 

natural gas is recovered, it can be sold as well, as long as a gathering line is available to convey

the recovered salable gas product to market or to further processing. A VRU cannot be used in 

all instances. Conditions that affect the feasibility of the use of a VRU include: the availability of 

electrical service sufficient to power the compressor; fluctuations in vapor loading caused by 

 

23 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Installing Vapor 

Recovery Units on Storage Tanks. Natural Gas Star Program. October 2006. 

http://www.epa.gov/gasstar/documents/ll_final_vap.pdf.

24 Supplement to the Wyoming Air Quality Standards and Regulations (WAQSR). Oil and Natural Gas Production 

Facilities. Chapter 6, Section 2 Permitting Guidance. Revised March 2010.
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surges in throughput and flash emissions from the storage vessel; potential for drawing air into 

condensate storage vessels causing an explosion hazard; and lack of appropriate destination or 

use for the vapor recovered.

Cost Impacts

Cost data for a VRU that were used in support of the 2012 NSPS obtained from an initial 

economic impact analysis prepared for proposed state-only revisions to a Colorado regulation are 

presented here.

25 We assumed cost information contained in the Colorado EIA to be given in 

2012 dollars. According to the Colorado economic impact analysis, the purchased equipment 

cost of a VRU was estimated to be $90,000. Total capital investment, including freight and 

design and installation was estimated to be $102,802. In addition, we included an estimated 

storage vessel retrofit cost of $68,736 assuming that the cost of retrofitting an existing storage 

vessel was 75 percent of the purchased equipment cost (e.g., VRU capital costs and freight and 

design cost).26 These cost data are presented in Table 4-3. We estimated total annual costs using 

2012 dollars to be $28,230 per year without recovered natural gas savings. The uncontrolled 

emissions from a storage vessel are largely dependent on the bbl/year throughput (see Table 4-2), 

which greatly influences both the controlled emissions and the cost of control per ton of VOC 

reduced. Costs may vary due to VRU design capacity, system configuration and individual site 

needs and recovery opportunities.

In order to assess the cost of control of a VRU for storage vessels that emit differing 

emissions, we evaluated the costs of routing VOC emissions from an existing storage vessel to a 

VRU for a storage vessel that emits 2 tpy, 4 tpy, 6 tpy, 8 tpy, 10 tpy, 12 tpy and 25 tpy to 

determine the level that would be cost-effective to control at a 95 percent control level. We 

estimated the cost of control without savings by dividing the total annual costs without savings 

by the tpy reduced. The cost of control with savings is calculated by assuming a 95 percent

reduction of VOC emissions by the VRU and converting the reduced VOC emissions to natural 

 

25 Initial Economic Impact Analysis for Proposed Revisions to the Colorado Air Quality Control Commission 

Regulation Number 7, Emissions of Volatile Organic Compounds. November 15, 2013.

26 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Installing Vapor 

Recovery Units on Storage Tanks. Natural Gas Star Program. October 2006. 

http://www.epa.gov/gasstar/documents/ll_final_vap.pdf.
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gas savings. Table 4-4 presents the estimated natural gas savings and the VOC cost per ton with 

and without savings. 
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Table 4-3. Total Capital Investment and Total Annual Costs of a Vapor Recovery Unit 

System

Cost Itema Cost

($2012)

Capital Costs Items

VRUa$90,000

Freight and Designa$1,648

VRU Installationa$11,154

Storage Vessel Retrofitb$68,736

Total Capital Investment $171,538

Annual Costs Items

Maintenance $9,396

Capital Recovery (7 percent interest, 15 year equipment life) ($/yr) $18,834

Total Annual Costs w/o Savings ($/yr) $28,230

a. Cost data from Initial Economic Impact Analysis (EIA) for proposed revisions to Colorado Air Quality Control 

Commission Regulation Number 7, Submitted with Request for Hearing Documents on November 15, 2013.

b. Assumes the storage vessel retrofit cost is 75 percent of the purchased equipment price (assumed to include vent system 

and piping to route emissions to the control device). Retrofit assumption from Exhibit 6 of the EPA Natural Gas Star 

Lessons Learned, Installing Vapor Recovery Units on Storage Tanks, October 2006.

Table 4-4. Costs of Routing Emissions from an Existing Storage Vessel to a VRU 

($/ton of VOC Reduced)

Storage Vessel 

Emissions

(tpy)

Cost per Ton of VOC Reduced ($2012)

Without Savings Natural Gas Savings 

(Mscf/yr)a With Savingsb

2 $14,858 $59 $14,734

4 $7,429 118 $7,305

6 $4,953 177 $4,828

8 $3,714 236 $3,590

10 $2,972 295 $2,847

12 $2,476 353 $2,352

25 $1,189 736 $1,065

a. The natural gas savings was calculated by assuming 95 percent VOC recovery and 31 Mscf/yr natural gas savings per ton of 

VOC recovered.

b. Assumes a natural gas price of $4.00 per Mcf.

Additionally, if a VRU is used to control VOC emissions from multiple storage vessels, 

the VOC emissions cost of control would be reduced because the cost for the additional storage
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vessel(s) would only include the storage vessel retrofit costs, and the overall VOC emission 

reductions would increase.

4.3.1.2 Routing Emissions to a Combustion Device

Description and Control Effectiveness

Combustors (e.g., enclosed combustion devices, thermal oxidizers and flares that use a 

high-temperature oxidation process) are also used to control emissions from storage vessels.

Combustors are used to control VOC in many industrial settings, since the combustor can 

normally handle fluctuations in concentration, flow rate, heating value and inert species 

content.27 For this analysis, we assumed that the types of combustors installed in the oil and 

natural gas industry can achieve at least a 95 percent control efficiency on a continuing basis.

28

A typical combustor used to control emissions from storage vessels in the oil and natural 

gas industry is an enclosed combustion system. The basic components of an enclosed 

combustion system include (1) piping for collecting emission source gases, (2) a single- or 

multiple-burner unit, (3) a stack enclosure, (4) an ignitor to ignite the mixture of emission source 

gas and air, and (5) combustor fuel/piping (as necessary). Figure 4-2 presents a schematic of a 

typical dual-burner enclosed combustion system.

Thermal oxidizers, also referred to as direct flame incinerators, thermal incinerators, or 

afterburners could also be used to control VOC emissions. Similar to a basic enclosed 

combustion device, a thermal oxidizer uses burner fuel to maintain a high temperature (typically 

800-850°C) within a combustion chamber. The VOC laden emission source gas is injected into 

the combustion chamber where it is oxidized (burned), and then the combustion products are 

exhausted to the atmosphere. Figure 4-3 provides a basic schematic of a thermal oxidizer.29

 

27 U.S. Environmental Protection Agency. AP 42, Fifth Edition, Volume I, Chapter 13.5 Industrial Flares. Office of 

Air Quality Planning & Standards. 1991.

28 U.S. Environmental Protection Agency. Air Pollution Control Technology Fact Sheet: FLARE. Clean Air 

Technology Center.

29 U.S. Environmental Protection Agency. Technology Transfer Network. Clearinghouse for Inventories and 

Emission Factors. Thermal Oxidizer. Website: cfpub.epa.gov/oarweb/mkb/contechnique.cfm?ControllD=17.
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Figure 4-2. Schematic of a Typical Enclosed Combustion System
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Figure 4-3. Basic Schematic of a Thermal Oxidizer

Cost Impacts

For combustors, we also obtained cost data from the initial EIA prepared for state-only 

revisions to the Colorado regulation.30 In addition to these cost data, we added a line-item for 

operating labor, a surveillance system, and data management. This is consistent with the 

guidelines outlined in the EPA’s Office of Air Quality Planning and Standards (OAQPS) Control 

Cost Manual (OCCM) for combustion devices and the EIA prepared for the 2012 NSPS.

31

However, OCCM guidelines specify that 630 operating labor hours per year for a combustion 

device, which we believe is unreasonable because many of these sites are unmanned and would 

most likely be operated remotely. Therefore, we assumed that the operating labor would be more 

similar to that estimated for a condenser in the OCCM, 130 hours per year. We estimated a total 

capital investment of $100,986 and a total annual costs of $22,228 per year. We included an 

additional cost of $68,736 (as discussed previously for VRUs) to estimate the cost of retrofitting 

an existing storage vessel to accommodate the use of a combustion device. Table 4-5 presents 

these cost data. 

 

30 Initial Economic Impact Analysis for Proposed Revisions to the Colorado Air Quality Control Commission 

Regulation Number 7, Emissions of Volatile Organic Compounds. November 15, 2013.

31 U.S. Environmental Protection Agency. OAQPS Control Cost Manual: Sixth Edition (EPA 452/B-02-001).

Research Triangle Park, NC.
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Table 4-5. Total Capital Investment and Total Annual Costs of a Combustor32

Cost Itema Cost

($2012)

Capital Costs Items

Combustora$18,169

Freight and Designa$1,648

Auto Ignitora$1,648

Surveillance Systemb,c,d $3,805

Combustor Installationa$6,980

Storage Vessel Retrofite$68,736

Total Capital Investment $100,986

Annual Costs Items

Operating Laborf$5,155

Maintenancef$4,160

Pilot Fuela$768

Data Managementc$1,057

Capital Recovery (7 percent interest, 15 year equipment life) ($/yr) $11,088

Total Annual Costs ($/yr) $22,228

a. Cost data from Initial Economic Impact Analysis for proposed revisions to Colorado Air Quality Control Commission 

Regulation Number 7, Submitted with Request for Hearing Documents on November 15, 2013.

b.

Surveillance system identifies when pilot is not lit and attempts to relight it, documents the duration of time when the pilot is 

not lit, and notifies and operator that repairs are necessary.

c. U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural 

Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New 

Source Performance Standards. April 2012. EPA Docket ID No.EPA-HQ-OAR-2010-0505-4550.

d. Cost obtained from 2012 NSPS TSD and escalated using the change in GDP: Implicit Price Deflator from 2008 to 2012 

(%)(which was 5.69 percent). Source: FRED GDP: Implicit Price Deflator from Jan 2008 to Jan 2012 

(http://research.stlouisfed.org/fred2/series/GDPDEF/#)

 

32 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document 

for the Final New Source Performance Standards. April 2012. EPA Docket Number EPA-HQ-OAR-2010-0505-

4550.
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e. Retrofit cost obtained from Storage Vessel Retrofit in Table 4-3 (assumed to include vent system and piping to route 

emissions to the control device).

f. Operating labor consists of labor resources for technical operation of device (130 hr/yr) and supervisory labor (15 percent of 

technical labor hours). Maintenance labor hours are assumed to be the same as operating labor (130 hr/yr). Labor rates are 

$32.00/hr (for technical and maintenance labor) and $51.03 (supervisory labor) and were obtained from the U.S. Department 

of Labor, Bureau of Labor Statistics, Employer Costs for Employee Compensation, December 2012.

As noted previously, storage vessels vary in size and throughputs and the uncontrolled 

emissions from a storage vessel are largely dependent on the bbl/year throughput (see Table 4-2), 

which greatly influences both the controlled emissions and cost of control. In order to assess the 

cost of control of combustion for storage vessels that emit differing emissions, we evaluated the 

costs of routing VOC emissions from an existing storage vessel to a combustion device for a 

storage vessel that emits 2 tpy, 4 tpy, 6 tpy, 8 tpy, 10 tpy, 12 tpy and 25 tpy to determine the 

level that would be cost-effective to control at a 95 percent control level. We estimated the cost 

of control without savings by dividing the total annual costs without savings by the tpy reduced. 

Table 4-6 presents these costs. The VOC emissions cost of control per ton of VOC reduced 

would be less if a combustion device is used to control VOC emissions from multiple storage 

vessels because the cost for the additional storage vessel(s) would only include storage vessel 

retrofit costs, and the overall VOC emission reductions would increase.

Table 4-6. Costs of Routing Emissions from an Existing Storage Vessel to a 

Combustion Device ($/ton of VOC Reduced)

Storage Vessel Emissions

(tpy)

Cost per Ton of VOC Reduced

($2012; Without Savings)

2 $11,114

4 $5,849

6 $3,900

8 $2,925

10 $2,340

12 $1,950

25 $936
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4.3.2 Existing Federal, State and Local Regulations

4.3.2.1 Federal Regulations that Specifically Require Control of VOC 

Emissions

Under the 2012 NSPS and 2013 NSPS Reconsideration, new or modified storage vessels 

with potential to emit VOC emissions of 6 tpy or more must reduce VOC emissions by at least 95 

percent, or demonstrate emissions from a vessel have dropped to less than four tpy of VOC

without emission controls for 12 consecutive months. 
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4.3.2.2 State and Local Regulations that Specifically Require Control of VOC 

Emissions33

States may have permitting restrictions on VOC emissions that may apply to an 

emissions source as a result of an operating, new source review (NSR) nonattainment, or 

prevention of significant deterioration (PSD) permit (e.g., on a case-by-case basis) based on air 

quality maintenance or improvement goals of an area. Permits specify what construction is 

allowed, what emission limits must be met, and how the source must be operated. To ensure that 

sources follow the permit requirements, permits also contain monitoring, recordkeeping, and 

reporting requirements. 

The environmental regulations in nine of the top oil and natural gas producing states

(sometimes with varying local ozone nonattainment area/concentrated area development 

requirements) (see Table 4-7) require the control of VOC emissions from storage vessels in the 

oil and natural gas industry. These states include California, Colorado, Kansas, Louisiana, 

Montana, North Dakota, Oklahoma, Texas and Wyoming. All except Wyoming require 95 

percent emission control with the application of a VRU or combustion (Wyoming requires 98 

percent control of emissions using a VRU or combustion).

Existing state regulations that apply to storage vessels in the oil and natural gas

industry apply to all storage vessels in a tank battery, or include an applicability threshold 

based on (1) capacity, (2) the vapor pressure of liquids contained in a storage vessel of a 

specified capacity and (3) the PTE of an individual storage vessel. Table 4-7 presents a brief

summary of the storage vessel emission control applicability cutoffs in regulations from these

nine states. Four states (Colorado, Montana, Texas and Wyoming) have applicability

thresholds in terms of VOC emissions. The remaining five states have storage vessel

regulations that are in terms of tank characteristics, such as vapor pressure, tank size or tank

contents. Equivalency of applicability thresholds based on tank and stored liquid 

characteristics and applicability thresholds based on VOC emissions cannot be determined. 

We analyzed the varying state VOC emission thresholds (based on a range of two tpy to 25 

 

33 Brown, Heather, EC/R Incorporated. Memorandum prepared for Bruce Moore, EPA/OAQPS/SPPD/FIG. Revised 

Analysis to Determine the Number of Storage Vessels Projected to be Subject to New Source Performance 

Standards for the Oil and Natural Gas Sector.
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tpy) as part of our cost of control analysis for VRUs and combustion devices in section 4.3.1 

of this chapter.

Table 4-7. Summary of Storage Vessel Regulations from Nine States

State/Local Authority Applicability Threshold

Texas

Applies to storage vessels with VOC emissions greater 

than 25 tpy.

California

Bay Area AQMD

Applies to storage vessels with capacity greater than 264

gallons.

California

Feather River AQMD

Applies to storage vessels with capacity greater than 

39,630 gallons.

California

Monterey Bay Unified APCD

Applies to storage vessels with capacity greater than 

39,630 gallons.

California

Sacramento Metropolitan AQMD

Applies to storage vessels with capacity greater than 

40,000 gallons.

California

San Joaquin Valley Unified

APCD

Applies to storage vessels with capacity greater than 1,100

gallons.

California

Santa Barbara County APCD

Applies to all storage vessels in tank battery (including

wash tanks, produced water tanks, and wastewater

tanks).

California South Coast AQMD

Applies to storage vessels with capacity greater than 

39,630 gallons with a true vapor pressure of 0.5 psia or

greater and storage vessels with a capacity greater than 

19,815 gallons with a true vapor pressure of 1.5 psia or

greater.

California Ventura County APCD

Applies to all storage vessels. Requirements depend on 

gallon capacity and true vapor pressure of material 

contained in vessel.

California Yolo-Solano AQMD

Applies to storage vessels with capacity greater than 

40,000 gallons.

North Dakota NDAC 33-15-07: submerged filling requirements to

control VOC for tanks >1,000 gallons.

Federal Implementation Plan (FIP): 

Fort Berthold Indian Reservation

Applies to all storage vessels (except those covered by 

NSPS subpart OOOO). There is no minimum threshold 

under the final FIP.

Louisiana

Applies to storage vessels more than 250 gallons up to

40,000 gallons with a maximum true vapor pressure of 1.5

psia or greater.
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State/Local Authority Applicability Threshold

Oklahoma

Applies to storage vessels with capacity greater than 

40,000 gallons (in ozone nonattainment areas).

Wyoming – Statewide Applies to storage vessels with greater than or equal to 10 

tpy VOC within 60 days of startup/modification.

Wyoming – Concentrated Development

Area

Applies to storage vessels with greater than or equal to 8 

tpy VOC, within 60 days of startup/modification.

Kansas

Permanent fixed roof storage tanks >40,000 gallons and 

external floating roof storage tanks.

Colorado

Condensate tanks with uncontrolled VOC emissions > 20 

tpy (2 tpy located at gas processing plants in ozone nonattainment areas).

Montana

Applies to oil or condensate storage tanks with a PTE 

greater than 15 tpy VOC.

4.4 Recommended RACT Level of Control

As discussed in section 4.3.2 of this chapter, existing federal and state and local 

regulations already require the reduction of VOC emissions from storage vessels in the oil and 

natural gas industry at or greater than 95 percent. While technologies such as a VRU and 

combustor (discussed in section 4.3.1 of this chapter) may achieve a 98 percent reduction of 

VOC emissions (and states such as Wyoming require 98 percent VOC emissions reduction level 

of control for storage vessels), data we reviewed in support of the NSPS indicated that 98 percent 

control is not technically achievable for all storage vessels.34 We believe that a 95 percent 

reduction of VOC emissions from storage vessels in the oil and natural gas industry is a 

reasonable recommended RACT level of control. This belief is supported by the wide use of this 

level of control in federal and state regulations that apply to storage vessels and because a 95 

percent level of control has been demonstrated to be technically achievable for storage vessels in

the oil and natural gas industry. 

Although sources have a choice on how they meet the recommended RACT level of 

control, the technologies that will likely be used to meet the recommended RACT level of 

 

34 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: New Source Performance Standards and 

National Emission Standards for Hazardous Air Pollutants Reviews. 40 CFR Parts 60 and 63. Response to 

Comments on Proposed Rule. August 23, 2011 (76 FR 52738). p. 128.
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control for oil and natural gas industry storage vessels are routing emissions to the process via a 

VRU or routing emissions to a combustion device. 

As discussed in section 4.2.2 of this chapter, the VOC emissions from storage vessels 

vary significantly, depending on the rate of liquid entering and passing through the vessel (i.e., 

its throughput), the pressure of the liquid as it enters the atmospheric pressure storage vessel, the 

liquid’s volatility and temperature of the liquid. Some storage vessels have negligible emissions, 

such as those with very little throughput and/or handling heavy liquids entering at atmospheric 

pressure where it would not be cost effective to require emission control requirements. Existing 

state regulations that apply to storage vessels in the oil and natural gas industry apply to all 

storage vessels in a tank battery, or include an applicability threshold based on (1) capacity, (2) 

the vapor pressure of liquids contained in a storage vessel of a specified capacity and (3) the PTE 

of an individual storage vessel. Based on information gathered under the 2012 NSPS, 35

throughput and capacity of a storage vessel is not always the best indicator of a storage vessels’

emissions, and we believe that the PTE of an individual storage vessel is preferable to use as an 

applicability threshold for storage vessels.

Based on our analyses conducted in support of the 2012 NSPS, 6 tpy was determined to

be a cost-effective applicability threshold for requiring 95 percent control of VOC emissions 

from new storage vessels (estimated to cost, on average, approximately $3,400 per ton of VOC 

reduced). Our analyses conducted for our RACT recommendation also found 6 tpy to be a costeffective applicability threshold for requiring 95 percent control of VOC emissions from existing 

storage vessels (estimated to cost, on average, between $3,900 and $4,800 per ton of VOC 

reduced). Based on these analyses, we recommend that the 95 percent VOC emission control of 

storage vessels only apply to storage vessels that emit greater than or equal to 6 tpy of VOC 

emissions. The VOC cost of control per ton of VOC reduced would be less if a combustion 

device or VRU is used to control VOC emissions from multiple storage vessels because the cost 

for the additional storage vessels would only include storage vessel retrofit costs, and the overall 

VOC emission reductions would increase.

In summary, we recommend the following as RACT for storage vessels in the oil and 

natural gas industry:

 

35 77 FR 49490, August 16, 2012
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(1) RACT for Condensate Storage Vessels: Reduce emissions by 95 percent from condensate 

storage vessels with a PTE > 6 tpy of VOC.

(2) RACT for Crude Oil Storage Vessels: Reduce emissions by 95 percent from crude oil 

storage vessels with a PTE > 6 tpy of VOC.

4.5 Factors to Consider in Developing Storage Vessel Compliance 

Procedures 

4.5.1 Compliance Recommendations When Using a Control Device

Improper design or operation of the storage vessel and its control system can result in 

occurrences where peak flow overwhelms the storage vessel and its capture systems, resulting in 

emissions that do not reach the control device, effectively reducing the control efficiency. We 

believe that it is essential that operators employ properly designed, sized and operated storage 

vessels to achieve effective emission control. We believe that such efforts on the part of owners 

and operators can result in more effective control of VOC emissions from storage vessels.

In order to ensure that VOC emissions are reduced by at least 95 percent (the 

recommended RACT level of control) from a storage vessel when using a control device or other 

control measure (such as routing to a process), the storage vessel should be equipped with a 

cover that is connected through a closed vent system that routes emissions to the control device 

(or process) that meets the RACT level of control. We recommend cover, closed vent system and 

control device design and compliance measures to ensure that control measures meet the RACT 

level of control. Recommended cover and closed vent system design and operation measures are 

specified in sections 4.5.1.1 and 4.5.1.2. Recommended control device operation and monitoring 

provisions for specified controls to ensure compliance are presented in sections 4.5.1.3 and 

4.5.1.4. The appendix to this document presents example model rule language that incorporates 

compliance elements recommended in this section that states may choose to use in whole or in 

part.

4.5.1.1 Recommendations for Cover Design

The cover and all openings on the cover (e.g., access hatches, sampling ports, pressure 

relief valves and gauge wells) should form a continuous impermeable barrier over the entire 

surface area of the liquid in the storage vessel or wet seal fluid degassing system. Each cover 
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opening should be secured in a closed, sealed position (gasket lid or cap) whenever material is in 

the unit except when it is necessary to open as follows:

(1) To add material to or remove material from the unit (including openings necessary to 

equalize or balance the internal pressure of the unit following changes in the level of 

material in the unit); 

(2) To inspect or sample the material in the unit; 

(3) To inspect, maintain, repair or replace equipment located in the unit; or

(4) To vent liquids, gases or fumes from the unit through a closed-vent system designed and 

operated in accordance specified control device requirements (see section 4.5.1.2) or to a 

process.

We recommend that you require the storage vessel thief hatch be equipped, maintained 

and operated with a weighted mechanism or equivalent, to ensure that the lid remains properly

seated. We also recommend that you require the gasket material for the hatch be selected based 

on composition of the fluid in the storage vessel and weather conditions.

We recommend requiring olfactory, visual and auditory inspections of covers for defects 

that could result in air emissions on a monthly basis. We recommend requiring that any detected 

defects be repaired as soon as technically feasible to minimize emissions (and prior to the end of 

the next shutdown).

4.5.1.2 Recommendations for Closed Vent Systems

The closed vent system should be designed and operated with no detectable emissions

(which can be monitored by monthly olfactory, visual and auditory inspections) and should be in 

operation at least 95 percent of the year. We recommend requiring that any detected defects be 

repaired as soon as technically feasible to minimize emissions (and prior to the end of the next 

shutdown).

With the exception of low leg drains, high point bleeds, analyzer vent, open-ended valves 

and safety devices, if the closed vent system contains one or more bypass devices that could be 

used to divert all or a portion of the gases, vapors, or fumes from entering the control device or 

to a process, we recommend requiring owners and operators either:

(1) Install, calibrate, maintain and operate a flow indicator at the inlet to the bypass device 

that could divert the stream away from the control device or process to the atmosphere 
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Storage Vessels 

that sounds an audible and visual alarm, or, initiates notification via remote alarm to the 

nearest field office, when the bypass device is open such that the stream is being, or could 

be, diverted away from the control device or process to the atmosphere; or 

(2) Secure the bypass device valve installed at the inlet to the bypass device in the nondiverting position using a car-seal or a lock-and-key type configuration. We recommend 

requiring bypass devices to be equipped with flow indicators that sound an alarm when 

the stream is diverted away from the control device or process to the atmosphere and that 

records be maintained of times when the alarm sounds.

4.5.1.3 Recommendations When “Routing to a Process” to a VRU 

Routing to a process would entail routing emissions via a closed vent system to any

enclosed portion of a process unit where the emissions are predominantly recycled and/or 

consumed in the same manner as a material that fulfills the same function in the process and/or 

transformed by chemical reaction into materials that are not regulated materials and/or 

incorporated into a product and/or recovered. Vapor recovery units and flow lines that “route 

emissions to a process” would be considered part of the process and would not be considered 

control devices that are subject to standards, but the cover and closed vent design, operation and 

monitoring requirements specified in sections 4.5.1.1 and 4.5.1.2 would apply.

4.5.1.4 Recommendations for Control Device Operation and Monitoring

If a control device is used to comply with the recommended RACT level of control, the 

device should be required to operate at all times when gases, vapors, and fumes are vented from 

the storage vessel affected facility through the closed vent system to the control device. The 

following paragraphs present select emission control options and suggested operation and 

monitoring requirements, as appropriate to ensure compliance with the RACT level of control.

Enclosed Combustion Devices

If an enclosed combustion device (e.g., thermal vapor incinerator, catalytic vapor 

incinerator, boiler or process heater) is used to meet the suggested RACT level of control, it 

should be designed to reduce the mass content of VOC emissions by 95 percent or greater; and

(1) maintained in a leak free condition, (2) installed and operated with a continuous burning pilot 

flame and (3) operated with no visible emissions. 
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Storage Vessels 

The visible emissions test (using section 11 of EPA Method 22, 40 CFR part 60, 

appendix A-7), inspection, repair and maintenance activities for each unit are recommended to 

be required and recorded in a maintenance and repair log that can be made available for 

inspection. Following return to operation from maintenance or repair activity, each device should 

be required to pass a Method 22 visual observation test as described in this paragraph. 

We recommend requiring that sources meeting the RACT level of control by routing 

emissions to a combustion device conduct performance tests and/or design analyses that 

demonstrate that the combustion device being used meets the required RACT level of control

(see section F of the appendix to this document for performance testing procedures for control 

devices that we recommend be used to demonstrate performance requirements).

Vapor Recovery Devices 

Vapor recovery devices (e.g., refrigerated condenser or carbon adsorption system) or 

other non-destructive control device must be designed and operated to reduce the mass content of 

VOC in the gases vented to the device by 95 percent by weight or greater. If a condenser is used, 

the condenser should be required to meet site-specific performance requirements (similar to 

those specified in 40 CFR 60.5417(f)(2)) and, if a carbon adsorption system is used, owners or 

operators should be required to establish a carbon replacement schedule for its carbon adsorption 

system that ensures continued compliance with the recommended RACT level of control. 

Condensers should be required to be equipped with a temperature monitoring device that 

continually records temperatures to ensure optimum operation and emission control is 

maintained (temperature sensor should be located in the exhaust vent from the condenser and 

should have a minimum accuracy of + one percent of the temperature being monitored in °C, or +

2.8°C, whichever value is greater). The carbon replacement schedule interval should be 

established using a performance test (e.g., as specified in 40 CFR 60.5413(b)) so that it is based 

on the total carbon working capacity of the control device and source operating schedule.
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5-1

Compressors

5.0 COMPRESSORS

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

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

consumer. The types of compressors that are used by the oil and natural gas industry as prime 

movers are reciprocating and centrifugal compressors. This chapter discusses the sources of 

VOC emissions from these compressors. This chapter also provides control techniques used to 

reduce VOC emissions from these compressors, along with costs and emission reductions. 

Finally, this chapter provides a discussion of our recommended RACT and the associated VOC 

emission reductions and costs for both reciprocating and centrifugal compressors.

5.1 Applicability

For the purposes of this guideline, the emissions and emission reductions discussed 

herein would apply to centrifugal and reciprocating compressors in the oil and natural gas 

industry located between the wellhead and point of custody transfer to the natural gas 

transmission and storage segment. As noted in section 3.2 of this document, we did not evaluate 

RACT for compressors located at a well site, or an adjacent well site and servicing more than 

one well site.

5.2 Process Description and Emission Sources

5.2.1 Process Description

5.2.1.1 Reciprocating Compressors

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

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

by the crankshaft powered by an internal combustion engine. Emissions occur when natural gas 

leaks around the piston rod when pressurized natural gas is in the cylinder. The compressor rod 

packing system consists of a series of flexible rings that create a seal around the piston rod to 

prevent gas from escaping between the rod and the inboard cylinder head. However, over time, 

during operation of the compressor, the rings become worn and the packaging system needs to be 
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5-2

Compressors

replaced to prevent excessive leaking from the compression cylinder. See Figure 5-1 for a 

depiction of a typical rod compressor packing system configuration.

36

Figure 5-1. Typical Reciprocating Compressor Rod Packing System Diagram

5.2.1.2 Centrifugal Compressors

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

natural gas where it is directed to a divergent duct section that converts the velocity energy to 

pressure energy. These compressors are primarily used for continuous, stationary transport of 

natural gas in the processing and transmission systems. Many centrifugal compressors use wet 

(meaning oil) seals around the rotating shaft to prevent natural gas from escaping where the 

compressor shaft exits the compressor casing. The wet seals use oil which is circulated at high 

pressure to form a barrier against compressed natural gas leakage. The circulated oil entrains and 

 

36 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Reducing Methane 

Emissions from Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.
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5-3

Compressors

adsorbs some compressed natural gas that may be released to the atmosphere during the seal oil 

recirculation process. Figure 5-2 illustrates the wet seal compressor configuration.

37

Figure 5-2. Typical Centrifugal Compressor Wet Seal

Alternatively, dry seals can be used in place of wet seals in centrifugal compressors. Dry seals 

prevent leakage by using the opposing force created by hydrodynamic grooves and springs (see 

Figure 5-3). The hydrodynamic grooves are etched into the surface of the rotating ring affixed to 

the compressor shaft. When the compressor is not rotating, the stationary ring in the seal housing 

is pressed against the rotating ring by springs. When the compressor shaft rotates at high speed, 

compressed natural gas has only one pathway to leak down the shaft, and that is between the 

rotating and stationary rings. This natural gas is pumped between the grooves in the rotating and 

stationary rings. The opposing force of high-pressure natural gas pumped between the rings and 

springs trying to push the rings together creates a very thin gap between the rings through which 

little natural gas can leak. While the compressor is operating, the rings are not in 

contact with each other, and therefore, do not wear or need lubrication. O-rings seal the 

stationary rings in the seal case.38

 

37 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Replacing Wet Seals 

with Dry Seals in Centrifugal Compressors. Natural Gas STAR Program. October 2006. 

http://epa.gov/gasstar/documents/ll_wetseals.pdf
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Compressors

Figure 5-3. Typical Centrifugal Compressor Tandem Dry Seal

Natural gas emissions from wet seal centrifugal compressors have been found to be 

higher than dry seal compressors primarily due to the off-gassing of the entrained natural gas 

from the oil. This natural gas is not suitable for sale and is either released to the atmosphere, 

flared, or routed back to a process. In addition to lower natural gas leakage (and therefore lower 

emissions), dry seals have been found to have lower operation and maintenance costs than wet 

seal compressors because they are a mechanically simpler design, require less power to operate, 

and are more reliable. For the same reasons we explained in the 2012 NSPS and the 2015 NSPS 

proposal, we are not recommending RACT for dry seal compressors and instead include the use 

of dry seal in place of a wet seal system as an available control option for reducing VOC 

emissions from wet seal centrifugal compressors (discussed in section 5.3.1.2 of this chapter). 

During the rulemakings for the 2012 NSPS and 2015 NSPS proposal, we found that the dry seal

system and the option of routing to a process both had at least 95 percent control efficiency.

 

38 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Replacing Wet Seals 

with Dry Seals in Centrifugal Compressors. Natural Gas STAR Program. October 2006. 

http://epa.gov/gasstar/documents/ll_wetseals.pdf
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Compressors

5.2.2 Emissions Data

5.2.2.1 Summary of Major Studies and Emissions

Several studies have been conducted that provide leak estimates from reciprocating and 

centrifugal compressors. Table 5-1 lists these studies, along with the type of information 

contained in the study. In addition to these sources, we evaluated the peer reviewer and public 

comments received on the EPA’s white paper, “Oil and Natural Gas Sector Compressors.”39

Table 5-1. Major Studies Reviewed for Emissions Data40

Report Name Affiliation Year of 

Report

Activity 

Factors

Emissions 

Data

Control 

Options

Inventory of Greenhouse 

Gas Emissions and Sinks: 

1990-2012a

EPA 2014 Nationwide X

Greenhouse Gas Reporting 

Program (Annual Reporting; 

Current Data Available for 

2011-2013)b

EPA 2014 FacilityLevel X X

Methane Emissions from the 

Natural Gas Industryc

EPA/Gas Research 

Institute (GRI)

1996 Nationwide X

Natural Gas STAR 

Programd,e EPA 1993-

2010 Nationwide X X

Natural Gas Industry 

Methane Emission Factor 

Improvement Studyf

URS Corporation, UT 

Austin, and EPA 2011 None Emission factors only

Characterizing Pivotal 

Sources of Methane 

Emissions from Natural Gas 

Production: Summary and 

Analysis of API and ANGA 

Survey Responsesg

API/ANGA 2012 Regional X

h

 

39 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Compressors. Report for Oil and Natural 

Gas Sector Compressors Review Panel. Office of Air Quality Planning and Standards (OAQPS). April 2014. 

Available at http://www.epa.gov/airquality/oilandgas/2014papers/20140415compressors.pdf

40 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document 

for the Final New Source Performance Standards. April 2012. EPA Docket Number EPA-HQ-OAR-2010-0505-

4550.
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Compressors

Report Name Affiliation Year of 

Report

Activity 

Factors

Emissions 

Data

Control 

Options

Economic Analysis of 

Methane Emissions 

Reduction Opportunities in 

the U.S. Onshore Oil and 

Natural Gas Industriesi

ICF International 

(Prepared for the 

Environmental Defense 

Fund (EDF)

2014 Regional X X

a. U.S Environmental Protection Agency. Greenhouse Gas Inventory: Emission and Sinks 1990-2012. Washington, DC.

b. U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: 

Climate Change Division. Washington, DC. November 2014.

c. U.S. Environmental Protection Agency/GRI. National Risk Management Research Laboratory. Research and Development.

Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. Prepared for the U.S. Department of Energy,

Energy Information Administration. EPA-600/R-96-080h. June 1996.

d. U.S. Environmental Protection Agency. Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing 

Systems. Natural Gas STAR. Environmental Protection Agency. 2006

e. U.S. Environmental Protection Agency. Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing 

Systems. Natural Gas STAR. Environmental Protection Agency. 2006.

f. URS Corporation/University of Texas at Austin. 2011. Natural Gas Industry Methane Emission Factor Improvement Study, 

Final Report. December 2011. http://www.utexas.edu/research/ceer/GHG/files/FReports/XA_83376101_Final_Report.pdf. 

g. American Petroleum Institute (API) and America’s Natural Gas Alliance (ANGA). Characterizing Pivotal Sources of Methane 

Emissions from Natural Gas Production. Summary and Analysis of API and ANGA Survey Responses. Final Report. September 

21, 2012.

h. The API/ANGA study provided information on equipment counts that could augment nationwide emissions calculations. No 

source emission information was included.

i.

ICF International. Economic Analysis of Methane Emissions Reduction Opportunities in the U.S. Onshore Oil and Natural Gas 

Industries. Prepared for the Environmental Defense Fund. March 2014.

5.2.2.2 Representative Reciprocating and Centrifugal Compressor 

Emissions

The centrifugal compressor methane emission factors used for processing are based on 

emission factor data for wet seals and dry seals from a sampling of wet seal and dry seal 

centrifugal compressor data in the 2012 GHG Inventory. 

For gathering and boosting station reciprocating compressors, the 2011 NSPS TSD 

emission factors were used because they are considered to be the best representative emission 

factors at this time. Emission factors in the Clearstone study42, which are expressed in thousand 

standard cubic feet per cylinder, were multiplied by the average number of cylinders per 

gathering and boosting station reciprocating compressor. The volumetric methane emission rate 

was converted to a mass emission rate using a density of 41.63 pounds of methane per thousand 

cubic feet. This conversion factor was developed assuming that methane is an ideal gas and using 

the ideal gas law to calculate the density. A summary of the reciprocating compressor methane

emission factors used for this analysis is presented in Table 5-2. Once the mass methane 

 

42 Clearstone Engineering Ltd. Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five 

Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites. (Draft): 2006.
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Compressors

emission rate was calculated, ratios were used to estimate VOC emissions using the methane to 

VOC pollutant ratios developed in the 2011 Gas Composition Memorandum. The specific ratio 

that was used to convert methane emissions to VOC emissions is 0.278 pounds VOC per pound 

of methane for the production and processing segments. Table 5-3 presents a summary of the 

estimated methane and VOC emissions per reciprocating and centrifugal compressor (in tpy) for 

the production and processing segments.

Table 5-2. Methane Emission Factors for Reciprocating and Centrifugal Compressors43

Oil and 

Gas 

Industry 

Segment

Reciprocating Compressors Centrifugal Compressors

Methane 

Emission 

Factor 

(scfhcylinder)

Average 

Number of 

Cylinders

Pressurized Factor 

(Percent of 

Hours/Year

Compressor 

Pressurized)

Wet Seal 

Methane 

Emission 

Factor 

(scfm)

Dry Seals 

Methane 

Emission 

Factor 

(scfm)

Gathering 

& Boosting

Stations

25.9a3.3 79.1% N/Ac N/Ac

Processing 57b2.5 89.7% 47.7d6

d

a. Clearstone Engineering Ltd. Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas 

Processing Plants and Upstream Gathering Compressor Stations and Well Sites. 2006.

b. U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry: Volume 8 – Equipment Leaks. 

Table 4-14. 

c. U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry: Volume 11 – Compressor 

Driver Exhaust. 1996 Report does not report any centrifugal compressors in the production or gathering/boosting segments, 

therefore no emission factor data were published for those two segments. 

d. U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. 

Greenhouse Gas Inventory: Emission and Sinks1990-2012. Washington, DC. April 2014. 

 

43 U.S. Environmental Protection Agency/GRI. Research and Development, National Risk Management Research 

Laboratory. Methane Emissions from the Natural Gas Industry. Prepared for the U.S. Department of Energy, Energy 

Information Administration. EPA-600/R-96-080h. June 1996.
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Compressors

Table 5-3. Baseline Methane VOC Emission Estimates for Reciprocating and Centrifugal 

Compressorsa

Industry Segment/Compressor Type

Baseline Emission 

Estimates

(tpy)

Methane VOC 

Reciprocating Compressors

Gathering and Boosting Stations 12.3 3.42

Processing 22 6.12

Centrifugal Compressors (Wet seals)

Processing 210.53 19.1

Centrifugal Compressors (Dry seals)

Processing 26 2.4

a.

For centrifugal compressors, it was assumed that 75 percent of the natural gas that is compressed is pipeline 

quality gas and 25 percent of the natural gas is production quality.

5.3 Available Controls and Regulatory Approaches

5.3.1 Available VOC Emission Control Options

Available controls for reducing VOC emissions from reciprocating and centrifugal 

compressors are presented in sections 5.3.1.1 and 5.3.1.2 of this chapter.

5.3.1.1 Reciprocating Compressors

Potential control options for reducing emissions from reciprocating compressors include 

control techniques that limit the leaking of natural gas past the piston rod packing. These options 

include (1) increasing or specifying the frequency of the replacement of the compressor rod 

packing, (2) increasing or specifying the frequency of the replacement of the piston rod, (3) 

specifying the refitting or realignment of the piston rod, and (4) routing of emission to a process 

through a closed vent system under negative pressure. In addition to these options, there are 

emerging control techniques where specific analyses have not yet been conducted. For example, 

there may be potential for reducing VOC emission by updating rod packing components made 

from newer materials which can help improve the life and performance of the rod packing 

system (economic rod packing replacement) and capturing gas from the reciprocating 

compressor and routing it back to the compressor engine to be used as fuel. These emerging 

VOC emissions control techniques are discussed briefly below, along with our evaluation of the 
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5-9

Compressors

frequency of compressor rod packing/piston rod replacement and piston rod refitting and 

realignment control options. 

We do not believe that combustion is a technically feasible control option because, as 

detailed in the 2011 NSPS TSD, routing of emissions to a control device can cause positive back 

pressure on the packing, which can cause safety issues due to gas backing up in the distance 

piece area and engine crankcase in some designs. While considering the option of routing of 

emissions to a process through a closed vent system under negative pressure, we determined that 

the negative pressure requirement not only ensures that all the emissions are conveyed to the 

process, it also avoids the issue of inducing back pressure on the rod packing and the resultant 

safety concerns. Although this option can be used in some circumstances, it cannot be applied in 

every installation. As a result, these options were not further considered under this guideline.

Frequency of Rod Packing Replacement

For reciprocating compressors, one of the options for reducing VOC emissions is a 

maintenance task that would increase or specify the frequency of replacement of the rod packing 

in order to reduce the leakage of natural gas past the piston rod. Over time the packing rings 

wear and allow more natural gas to escape around the piston rod. Regular replacement of these 

rings reduces VOC emissions. Therefore, this control technique is considered to be an available 

VOC emission control technique for reciprocating compressors. 

Description

As noted previously, reciprocating compressor rod packing consists of a series of flexible 

rings that fit around a shaft to create a seal against leakage. As the rings wear, they allow more 

compressed natural gas to escape, increasing rod packing emissions. Rod packing emissions 

typically occur around the rings from slight movement of the rings in the cups as the rod moves, 

but can also occur through the “nose gasket” around the packing case, between the packing cups, 

and between the rings and shaft. If the fit between the rod packing rings and rod is too loose, 

more compressed natural gas will escape. Periodically replacing the packing rings ensures the 

correct fit is maintained between packing rings and the rod. 44

 

44 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Reducing Methane 

Emissions from Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.
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5-10

Compressors

Control Effectiveness

As discussed above, regular replacement of the reciprocating compressor rod packing can 

reduce the leaking of natural gas across the piston rod. The potential emission reductions for 

gathering and boosting stations and the processing segment were calculated by comparing the 

average rod packing emissions with the average emissions from newly installed and worn-in rod 

packing. 

Based on industry information from the Natural Gas STAR Program, we have determined 

that the additional cost of shortening the replacement period more frequently than every three 

years or every 26,000 hours would not be justified based on the additional emission reductions 

that would be achieved.45 Therefore, we analyzed emission reductions that would result from 

replacing worn packing with newly installed packing at a frequency of every three years or every

26,000 hours. For the baseline, we assumed that rod packing is replaced every four years. The 

analysis uses Equation 1 for estimating gathering and boosting station emission reductions, and 

Equation 2 for estimating processing segment emission reductions that would result from 

replacing worn packing with newly installed packing at a frequency of every 3 years or every

26,000 hours.46

Where:

G B RWP&

= Potential methane emission reductions from gathering and boosting station 

compressors by replacing worn packing with newly installed packing, in million cubic 

feet per year (MMcf/year);

G B CompExisting&

= Number of existing gathering and boosting station compressors;

 

45 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: New Source Performance Standards and 

National Emission Standards for Hazardous Air Pollutants Reviews. 40 CFR Parts 60 and 63. Response to Public 

Comments on Proposed Rule. August 23, 2011 (76 FR 52738). pg. 102.

46

 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil 

and Natural Gas Production, Transmission, and Distribution – Background Technical Support Document for 

Proposed Standards. July 2011. EPA Document Number EPA-453/R-11-002.

Equation 1

 

6

&

&

&

10

   8760



Comp E E C O

R

G B New

G B

G B Existing

WP
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5-11

Compressors

EG&B = Methane emission factor for gathering and boosting station compressors, in cubic 

feet per hour per cylinder (25.9 scfh-cylinder);

ENew =Average emissions from a newly installed rod packing, assumed to be 11.5 cubic 

feet per hour per cylinder47 for this analysis;

C = Average number of cylinders for gathering and boosting station compressors (i.e., 

3.3) 

O = Percent of time during the calendar year the average gathering and boosting station 

compressor is in the operating and standby pressurized modes, 79.1 percent;

8760 = Number of hours in a year;

106 = Number of cubic feet in a million cubic feet.

Equation 2

 

6

10

   8760



Comp E E C O

R

P New

P

Existing

P

Where:

RP= Potential methane emission reductions from processing compressors replacing worn 

packing to newly installed packing, in million cubic feet per year (MMcf/year);

P CompExisting= Number of existing processing compressors;

EP = Methane emission factor for processing compressors, in cubic feet per hour per 

cylinder, 57 scfh-cylinder;

ENew =Average emissions from a newly installed rod packing, assumed to be 11.5 cubic 

feet per hour per cylinder48 for this analysis;

C = Average number of cylinders for processing compressors (i.e., 2.5); 

O = Percent of time during the calendar year the average processing compressor is in the 

operating and standby pressurized modes, 89.7 percent;

8760 = Number of hours in a year;

106 = Number of cubic feet in a million cubic feet.

 

47 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Reducing Methane 

Emissions from Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.

48 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Reducing Methane 

Emissions from Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.
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Compressors

Table 5-3 presents a summary of the potential emission reductions for reciprocating 

compressor rod packing replacement for gathering and boosting station compressors and 

processing segment compressors based on the percent natural gas reduction calculated from the 

above equations. The emissions of VOC were estimated using the methane emissions 

calculated above and the methane-to-VOC- ratio developed for each of the segments in the 

2011 Gas Composition Memorandum.

Table 5-4. Estimated Annual Reciprocating Compressor Emission Reductions from 

Increasing the Frequency of Rod Packing Replacement

Oil and Natural Gas 

Segment

Individual Compressor 

Emission Reductions 

(tons/compressor-year)

Methane VOC

Gathering and 

Boosting 6.84 1.9

Processing 17.58 4.89

Cost Impacts

Costs for the specified frequency of replacement of reciprocating compressor rod packing 

documented in the 2011 NSPS TSD were obtained from a Natural Gas STAR Lessons Learned

document which estimated the cost to replace the packing rings to be $1,712 per cylinder 

(converted from 2008 dollars to 2012 dollars). It was assumed that rod packing replacement 

would occur during planned shutdowns and maintenance, and therefore no additional travel costs 

would be incurred for implementing the rod packing replacement program. In addition, no costs 

were included for monitoring because the rod packing replacement is based on the number of 

hours that the compressor operates or the period of time since the previous replacement. The 

2011 NSPS TSD analysis assumed that, at baseline, the replacement of rod packing for 

reciprocating compressors occurs on average every four years based on industry information 

from the Natural Gas STAR Program. The cost impacts are based on the replacement frequency

of the rod packing every 26,000 hours that the reciprocating compressor operates in the 

pressurized mode. 

The 26,000 hour replacement frequency used for the cost impacts in the 2011 NSPS TSD 

was determined using a weighted average of the annual percentage that the reciprocating 

compressors are pressurized. The weighted average percentage was calculated to be 98.9 percent. 
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Compressors

This percentage was multiplied by the total number of hours in 3 years to obtain a value of 

26,000 hours. Assuming an interest rate of 7 percent, the capital recovery factors (based on 

replacing the rod packing every 3 years or 26,000 hours) were calculated to be 0.3122 and 

0.3490 for gathering and boosting stations and the processing segment, respectively. The capital 

costs were calculated using the average rod packing cost of $1,712 (converted from $1,620 in 

2008 dollars to 2012 dollars) and the average number of cylinders per compressor (assumed to 

be 3.3 cylinders for gathering and boosting compressors and 2.5 cylinders for processing 

segment compressors).49 The annual costs were calculated using the capital costs and the capital 

recovery factors. Table 5-4 presents a summary of the capital and annual costs for gathering and 

boosting stations and the processing segment.

There are monetary savings associated with the amount of gas saved with reciprocating 

compressor rod packing replacement. Monetary savings associated with the amount of gas saved 

with reciprocating compressor rod packing replacement was estimated using a natural gas price 

of $4.00 per Mcf.50 Table 5-5 presents the annual costs with savings and cost of control for 

reciprocating rod packing replacement for gathering and boosting stations and the processing 

segment. 

Reciprocating compressor rod packing replacement prevents the escape of natural gas 

from the piston rod. In addition to reducing VOC emissions there would be a co-benefit of 

reducing other emissions (such as methane) as a result of increasing the frequency of rod packing 

replacement. 

 

49 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution – Background Technical Support Document for Proposed 

Standards. July 2011. EPA Document Number EPA-453/R-11-002.

50 U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price. Energy Information 

Administration Natural Gas Navigator. Retrieved online on December 12, 2010 at 

http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm
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Table 5-5. Cost of Control for Increasing the Frequency of Reciprocating Compressor Rod 

Packing Replacement

Oil and Gas 

Segment

Capital 

Costs

($2012)a

Annual Costs per 

Compressor 

($/compressor-year)

VOC Cost of Control

($/ton)

Without 

Savings

With 

Savings

Without 

Savings

With 

Savings

Gathering 

and Boosting

$5,650 $2,153 $566 $1,132 $298

Processing $4,280 $1,631 ($2,443) $334 ($500)

a. 2011 TSD 2008 dollars converted to 2012 dollars using the Federal Reserve Economic Data GDP Price Deflater (5.69 

percent).

Frequency of Replacement and/or Realignment/Retrofitting of the Piston Rod

Like the packing rings, piston rods on reciprocating compressors also deteriorate. Piston 

rods, however, wear more slowly than packing rings, having a life of about 10 years.51 Rods 

wear “out-of-round” or taper when poorly aligned, which affects the fit of packing rings against 

the shaft (and therefore the tightness of the seal) and the rate of ring wear. An out-of-round shaft 

not only seals poorly, allowing more leakage, but also causes uneven wear on the seals, thereby 

shortening the life of the piston rod and the packing seal. Replacing or upgrading the rod can 

reduce reciprocating compressor rod packing emissions. Also, upgrading piston rods by coating 

them with tungsten carbide or chrome reduces wear over the life of the rod. We assume that 

operators will choose, at their discretion, when to replace/realign or retrofit the rod as part of 

regular maintenance procedures and replace the rod when appropriate when the compressor is 

out of service for other maintenance such as rod packing replacement. Therefore, we did not 

consider this option any further. 

Updated Rod Packing Material 

Although specific analyses have not been conducted, there may be potential for reducing 

VOC emissions by updating rod packing components made from newer materials, which can 

help improve the life and performance of the rod packing system. One option is to replace the 

bronze metallic rod packing rings with longer lasting carbon-impregnated Teflon rings. 

 

51 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Reducing Methane 

Emissions from Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.
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Compressor rods can also be coated with chrome or tungsten carbide to reduce wear and extend 

the life of the piston rod.52 Although changing the rod packing material has been identified as a 

potential VOC emission reduction option for reciprocating compressors, there is insufficient 

information on its emission reduction potential and use throughout the industry.

Economic Rod Packing Replacement

Another option facilities can use that has the potential to reduce costs and emissions is for 

facilities to use specific financial objectives and monitoring data to determine emission levels at 

which it is cost effective to replace rings and rods. Benefits of calculating and utilizing this 

“economic replacement threshold” include VOC emission reductions and natural gas cost 

savings. Using this approach, one Natural Gas STAR partner reportedly achieved savings of over 

$233,000 annually at 2006 gas prices. An economic replacement threshold approach would also 

result in operational benefits, including a longer life for existing equipment, improvements in 

operating efficiencies, and long-term savings.53

Gas Recovery (Routing of Emissions to a Process)

Description 

Another control option for reciprocating compressors includes control techniques that 

recover natural gas leaking past the piston rod packing. We are aware of a system that captures 

the natural gas that would otherwise be vented and routes it back to the compressor engine to be 

used as fuel.54 The vent gases are passed through a valve train that includes a demister and then 

are injected into the engine intake air after the air filter. In general, the technology consists of 

recovering vented emissions from the rod packing under negative pressure and routing these 

emissions of otherwise vented gas to the air intake of a reciprocating internal combustion engine 

that would burn the gas as fuel to augment the normal fuel supply. The system’s computerized 

air/fuel control system would then adjust the normal fuel supply to accommodate the increased 

fuel made available from the recovered emissions and thereby take advantage of the recovered 

emissions while avoiding an overly rich fuel mixture.

 

52 Ibid.

53 U.S. Environmental Protection Agency. Lessons Learned: Reducing Methane Emissions from Compressor Rod 

Packing Systems. Natural Gas STAR. Environmental Protection Agency. 2006.

54 REM Technology Inc. and Targa Resources. Reducing Methane and VOC Emissions. Presentation for the 2012 

Natural Gas STAR Annual Implementation Workshop.
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Subpart OOOO, as well as the 2015 proposed subpart OOOOa, provide a compliance 

option for reciprocating compressors that allows collecting emissions from the rod packing using 

a rod packing emissions collection system which operates under negative pressure and routing 

the rod packing emissions to a process through a closed vent system. Both of the above systems, 

if installed using a closed vent system meeting the subpart OOOO and subpart OOOOa 

requirements, could potentially be used for this compliance option.

Control Effectiveness 

One estimate obtained by the EPA states that the gas recovery system can result in the 

elimination of over 99 percent of VOC and methane emissions that would otherwise occur from 

the venting of the emissions from the compressor rod packing.55 The emissions that would have 

been vented are combusted in the compressor engine to generate power. 

If the facility is able to route rod packing vents to a VRU system, it is possible to recover 

approximately 95-100 percent of emissions. If the gas is routed to a flare, approximately 95

percent of the methane and VOC are reduced. 

Cost Impacts

One estimate reported that the cost per engine would be approximately $12,000 (does not 

include installation costs). Some costs would be mitigated by fuel gas savings, as using the 

captured gas to displace some of the purchased fuel would require less fuel to be purchased in 

order to run the compressor engine. The fuel cost saving based on a 4 throw compressor with 

moderate leak rate would be an estimated $6,500 per year.56 This technique is discussed further 

in the Natural Gas STAR PRO Fact Sheet titled “Install Automated Air/Fuel Ratio Controls”.

57

This document reported an average fuel gas savings of 78 Mcf/day per engine with the gas 

recovery system installed. Based on our review of information on this technology, we conclude 

that this technology has merit and would provide better emission reductions than increasing the 

replacement of rod packing from every 4 years to every 3 years since the emissions would be 

captured under negative pressure, allowing all emissions to be routed to the engine. It is our 

 

55 REM Technology Inc., et al. Profitable Use of Vented Emission in Oil & Gas Production. Prepared with support 

from the Climate Change and Emissions Management Corporation (CCEMC). 2013.

56 REM Technology Inc. Presentation to the U.S. Environmental Protection Agency on December 1, 2011. EPA 

Docket ID No. EPA-HQ-OAR-2010-0505.

57 U.S. Environmental Protection Agency. Gas STAR PRO No. 104. Install Automated Air/Fuel Ratio Controls. 

2011. Available at: http://epa.gov/gasstar/documents/auto-air-fuel-ratio.pdf.
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understanding that this technology may not be applicable to every compressor installation and 

situation.

For a VRU, assuming the proper equipment is already available at the facility, capturing 

the rod packing emissions would require minimal costs. The investment would only need to 

include the cost of piping and installation. While we have not obtained a cost estimate 

specifically for routing rod packing vents to a VRU, this process has been studied for 

dehydrators and would be similar for rod packing systems. According to the Natural Gas STAR 

PRO Fact Sheet titled “Pipe Glycol Dehydrator to Vapor Recovery Unit,”58 the cost for planning 

and installing additional piping is approximately $2,000. Routing to a VRU also provides 

additional incentive as there is a value associated with recovered gas. However, the installation 

of a VRU to only capture rod packing emissions may not be economically viable if an additional 

compressor system is required. If the VRU is already present at the facility, the incremental cost 

to capture the rod packing vent gas can be recovered from the value of the additional captured 

natural gas.

Although gas recovery has been identified as a potential VOC emission reduction option 

for reciprocating compressors, there is insufficient information on its availability as a reasonably 

available control option for reducing reciprocating compressor VOC emissions. However, we 

recommend that regulatory agencies consider this technology as a compliance option when 

implementing the RACT recommendations presented in section 5.4 of this chapter.

5.3.1.2 Centrifugal Compressors Equipped with Wet Seals

Potential control options to reduce emissions from centrifugal compressors equipped with 

wet seals include control techniques that limit the leaking of natural gas across the rotating shaft, 

and capture and destruction of the emissions by routing emissions to a process (e.g., a 

compressor or fuel gas system) or to a combustion device (discussed in detail in sections 4.3.1.2 

of chapter 4). We evaluate below three available control options: (1) converting wet seals to dry

seals; (2) routing emissions to a fuel gas system or compressor (process); and (3) routing 

emissions to a combustion device.

 

58 U.S. Environmental Protection Agency. Gas STAR PRO No. 203. Pipe Glycol Dehydrator to Vapor Recovery 

Unit. 2011. Available at: http://epa.gov/gasstar/documents/pipeglycoldehydratortovru.pdf.
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Converting Wet Seals to Dry Seals

Description

We evaluated the use of centrifugal compressor dry seals as an available VOC control 

option for wet seal centrifugal compressors. As noted in section 5.2.1 of this chapter, the VOC 

emission profile from the use of dry seals is considerably less than from the use of wet seals. 

Replacing wet seals with dry seals can therefore substantially reduce VOC emissions across the 

rotating shaft compared to wet seals, while simultaneously reducing operating costs and 

enhancing compressor efficiency compared to wet seals. During normal operation, dry seals leak 

at a rate of 6 scfm methane per compressor.59 While this is equivalent to a wet seal’s leakage rate 

at the seal face, wet seals generate additional emissions during degassing of the circulating oil. 

Gas separated from the seal oil before the oil is recirculated is usually vented to the atmosphere, 

bringing the total leakage rate for tandem wet seals to 47.7 scfm methane per compressor.60,61 It

is not practical or feasible in all situations, however, to retrofit an existing wet seal compressor 

with a dry seal compressor. We have received information that indicates that the conversion 

process requires a significant period of time to complete and the compressor would need to be 

out of commission for the conversion period. 

Control Effectiveness

The emission reductions that would occur by replacing wet seal compressors with a dry

seal compressor were calculated by subtracting the dry seal emissions from the emissions from 

a centrifugal compressor equipped with wet seals. We used the centrifugal compressor 

emission factors in Table 5-2 and estimated that VOC emissions would be reduced by 16.7 tpy

per compressor. 

Cost Impacts

The Natural Gas STAR Program estimated the cost of retrofitting dry seals on a 

centrifugal compressor equipped with wet seals to be $324,000 ($342,439 in 2012 dollars) for a 

 

59 U.S. Environmental Protection Agency. Lessons Learned Document. Replacing Wet Seals with Dry Seals in 

Centrifugal Compressors. October 2006. Available at http://epa.gov/gasstar/documents/ll_wetseals.pdf. 

60 U.S. Environmental Protection Agency, et al. Methane’s Role in Promoting Sustainable Development in the Oil 

and Natural Gas Industry. World Gas Conference 10/2009. Available at: 

http://www.epa.gov/gasstar/documents/best_paper_award.pdf

61 U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions from Natural Gas 

Systems. Inventory of U.S. Greenhouse Gas Emission and Sinks: 1990-2012. Washington, DC. Annex 3. Table A129.
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two-seal dry seal system, which includes the cost of both seals and the dry gas conditioning, 

monitoring, control console and installation.62 The annual costs were calculated as the capital 

recovery of the capital costs assuming a 20-year equipment life and 7 percent interest which is 

approximately $32,324 per compressor. The Natural Gas STAR Program estimated that the 

annual operation and maintenance savings from the installation of a dry seal compressor is 

$88,300 ($93,325 in 2012 dollars) in comparison to a wet seal compressor. In addition, the 

installation of dry seals reduces natural gas emissions by 10,721 Mscf/yr63 which results in an 

estimated natural gas savings of $42,883 per year assuming a natural gas price of $4/Mcf. A 

summary of the capital and annual costs for replacing a wet seal compressor with a dry seal 

compressor is presented in Table 5-5 along with the VOC cost of control. As noted above, we 

have received information that indicates that the conversion process requires a significant period 

of time to complete and the compressor would need to be out of commission during the 

conversion period. Because of this, a facility may have to provide a temporary compressor in the 

interim that would add additional costs to the cost estimates we present in Table 5-6.

Table 5-6. Cost of Control of Replacing a Wet Seal Compressor with a Dry Seal

Compressor

Oil & Natural Gas

Segment

Capital 

Costs

($2012)

Annual Costs Per Compressor 

($/compressor-year)

VOC Cost of Control

($/ton)

Without 

Savings a

With O&M and 

Natural Gas 

Savings b

Without 

Savings

With O&M and 

Natural Gas

Savings

Processing $342,439 $32,324 ($103,884) $1,931 ($6,205)

a.

Includes only the annualized capital costs of the retrofit of the dry seal system (20 years, 7% interest).

b.

Includes the annualized capital costs, annual O&M savings and annual natural gas savings.

Routing Emissions to a Compressor or Fuel Gas System (Process) 

Description

One option for reducing VOC emissions from the compressor wet seal fluid degassing 

system is to route the captured emissions back to the compressor suction or fuel system or other 

beneficial use (referred to collectively as routing to a process). Routing to a process would entail 

 

62 U.S. Environmental Protection Agency. Lessons Learned Document. Replacing Wet Seals with Dry Seals in 

Centrifugal Compressors. October 2006. Available at http://epa.gov/gasstar/documents/ll_wetseals.pdf.

63 The natural gas savings was calculated by using the 16.7 tpy VOC reduction and dividing by the VOC/methane 

weight ratio of 0.278 to determine the amount of methane reduction that would be reduced (60.1 tpy). The methane 

emission reductions were converted to volumetric natural gas reductions assuming a natural gas density of 0.02082 

tons/Mcf and a 82.9 volume percent conversion factor of methane to natural gas.
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routing emissions via a closed vent system to any enclosed portion of a process unit (e.g., 

compressor or fuel gas system) where the emissions are predominantly recycled, consumed in 

the same manner as a material that fulfills the same function in the process, transformed by 

chemical reaction into materials that are not regulated materials, incorporated into a product, or 

recovered. Emissions that are routed to a process are assumed to result in the same or greater 

emission reductions as would have been achieved had the emissions been routed through a 

closed vent system to a combustion device. Table 5-7 presents a summary of the estimated 

emission reductions from routing emissions from the wet seal fluid degassing system to a 

process. For purposes of this analysis, we assume that routing VOC emissions from a wet seal 

fluid degassing system to a process reduces VOC emissions greater than or equal to a 

combustion device (i.e., greater than or equal to 95 percent).

Table 5-7. Estimated Annual Centrifugal Compressor VOC Emission Reductions for 

Routing Wet Seal Fluid Degassing System to a Process64,65

Oil & Gas Segment

Individual Compressor 

VOC Emission Reductions 

(tons/compressor-year)

Processing > 18.1

Cost Impacts

The capital costs of a system to route the seal oil degassing system to a process is 

estimated to be $23,252,66 converting to 2012 dollars using the Federal Reserve Economic Data 

GDP Price Deflater (Change in GDP: Implicit Price Deflator from 2008 to 2012 (5.69 

percent)).

67 The estimated costs include an intermediate pressure degassing drum, new piping, 

 

64 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document 

for the Final New Source Performance Standards. April 2012. EPA Docket Number EPA-HQ-OAR-2010-0505-

4550.

65 Ibid.

66 Ibid.

67 U.S. Bureau of Economic Analysis. Gross Domestic Product: Implicit Price Deflator (GDPDEF], retrieved from 

FRED, Federal Reserve Bank of St. Louis. https://research.stlouisfed.org/fred2/series/GDPDEF/ March, 

26, 2015.
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gas demister/filter, and a pressure regulator for the fuel line. The annual costs were estimated to 

be $2,553 assuming a 15 year equipment life at 7 percent interest.

Potential natural gas savings for this option were estimated to be 12 Mcf/yr and assumes 

that greater than or equal to 95 percent of the 47.7 scfm methane emissions are controlled, an 

annual operating factor of 43.6 percent, and the 82.9 volume percent conversion factor of 

methane to natural gas. Assuming a natural gas savings of $4/Mcf, the natural gas savings 

equates to approximately $47,553 per year. Table 5-8 presents a summary of the cost of control 

for routing emissions to a process.

Table 5-8. VOC Cost of Control for Routing Wet Seal Fluid Degassing System to a Processa

Oil and Gas 

Segment

Capital 

Costs

($2012)a

Annual Costs per 

Compressor 

($/compressor-year)

VOC Cost of Control 

($/ton)

Without 

Savings

With 

Savings

Without 

Savings

With 

Savings

Processing $23,252 $2,553 ($47,553) $141 ($2,621)

NA = Not Applicable 

a. 2011 TSD 2008 dollars converted to 2012 dollars using the Federal Reserve Economic Data GDP Price Deflater (Change in 

GDP: Implicit Price Deflator from 2008 to 2012 (5.69 percent)).68

Routing Emissions to a Combustion Device 

Description

Combustion devices are commonly used in the oil and natural gas industry to combust 

VOC emission streams. A combustion device generally achieves 95 percent reduction of VOC 

when operated according to the manufacturer instructions. Typical combustion devices used in 

the oil and natural gas industry to control VOC emissions are discussed in greater detail in 

section 4.3.1.2 of chapter 4 of this document. For this analysis, we assumed that the entrained 

natural gas from the seal oil that is removed in the degassing process would be directed to a 

combustion device that achieves a 95 percent reduction of VOC. The wet seal emissions in Table 

5-2 were used along with the control efficiency to calculate the emission reductions. Table 5-9

 

68 U.S. Bureau of Economic Analysis, Gross Domestic Product: Implicit Price Deflator (GDPDEF], retrieved from 

FRED, Federal Reserve Bank of St. Louis. https://research.stlouisfed.org/fred2/series/GDPDEF/ March, 

26, 2015.
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presents a summary of the estimated emission reductions from routing emissions from the wet 

seal to a combustion device.

Table 5-9. Estimated Annual VOC Emission Reductions for Routing Wet Seal Fluid

Degassing System to a Combustion Device69,

Oil & Gas Segment

Individual Compressor 

VOC Emission Reductions 

(tons/compressor-year)

Processing 18.1

Cost Impacts

Routing the captured gas from the centrifugal compressor wet seal degassing system to 

an existing combustion device or installing a new combustion device has associated capital 

costs and operating costs. The capital and annual costs of the combustion device (an enclosed 

flare for the analysis) were calculated using the methodology in the EPA Control Cost 

Manual.70 However, Control Cost Manual guidelines specify that 630 operating labor hours per 

year for a combustion device, which we believe is unreasonable because many of these sites 

are unmanned and would most likely be operated remotely. Therefore, we assumed that the 

operating labor would be more similar to that estimated for a condenser in the Control Cost 

Manual, which is 130 hours per year. The heat content of the gas stream was calculated using 

information from the 2011 Gas Composition Memorandum. Table 5-10 presents a summary of 

the capital and annual costs for wet seals routed to a flare, as well as the VOC cost of control. 

There is no cost savings estimated for this option because the recovered natural gas is 

combusted.

 

69 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document 

for the Final New Source Performance Standards. April 2012. EPA Docket Number EPA-HQ-OAR-2010-0505-

4550.

70 U.S. Environmental Protection Agency. OAQPS Control Cost Manual: Sixth Edition (EPA 452/B-02-001).

Research Triangle Park, NC.

.
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Table 5-10. Cost of Control for Routing Wet Seal Fluid Degassing System to a Combustion 

Device 

Industry 

Segment

Capital Costs

($)

Annual Costs per 

Compressor 

($/compressor-year)

VOC Cost of 

Control 

New CD

($/ton)

VOC Cost of 

Control 

Existing CD

New CD ($/ton) Existing 

CD New CD Existing CD

Processing $71,783 $23,252 $114,146 $3,311 $6,292 $183

CD = Control Device

5.3.2 Existing Federal, State and Local Regulations

5.3.2.1 Federal Regulations that Specifically Require Control of VOC 

Emissions

Under the 2012 NSPS, reciprocating compressors are required to limit VOC emissions by

replacing the rod packing after 26,000 hours of operation or 36 months since the previous rod 

packing replacement. Alternatively, an owner or operator is allowed to route rod packing 

emissions to a process through a closed vent system under negative pressure. For centrifugal 

compressors in the processing segment, the 2012 NSPS requires that VOC emissions be reduced 

from each centrifugal compressor wet seal fluid degassing system by 95 percent. 

5.3.2.2 State and Local Regulations that Specifically Require Control of VOC 

Emissions

States may have permitting restrictions on VOC emissions that may apply to an 

emissions source as a result of an NSR NA or PSD permit (e.g., on a case-by-case basis) 

requirements based on air quality maintenance or improvement goals of an area. Permits specify

what construction is allowed, what emission limits must be met, and often how the source must 

be operated. To assure that sources follow the permit requirements, permits also contain 

monitoring, recordkeeping, and reporting requirements. 

Montana requires oil and natural gas well facilities to control emissions from the time the 

well is completed until the source is registered or permitted. Each piece of oil or natural gas well 

facility equipment, with VOC vapors of 200 Btu/scf or more with a PTE greater than 15 tpy, is 

required to (1) capture and route emissions to a natural gas pipeline, (2) route to a smokeless 

combustion device equipped with an electronic ignition device or a continuous burning pilot 
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system meeting the requirements of 40 CFR 60.18 and operating at 95 percent or greater control 

efficiency, or (3) route to air pollution control equipment with equal or greater control efficiency

than a smokeless combustion device. This includes the control of emissions from compressor 

engines used for transmission of natural gas (Registration of Air Contaminant Sources, Rule 

17.8.1711 Oil or Gas Well Facilities Emission Control Requirements). 

Colorado (Regulation 7, XVII.B.3.b and c) requires that uncontrolled actual hydrocarbon 

emissions from wet seal fluid degassing systems on wet seal centrifugal compressors be 

controlled by at least 95 percent, unless the centrifugal compressor is subject to 40 CFR part 60, 

subpart OOOO. Additionally, Regulation 7 requires that rod packing on any reciprocating

compressor located at a natural gas compressor station be replaced every 26,000 hours of 

operation or every 36 months, unless the reciprocating compressor is subject to 40 CFR part 60, 

subpart OOOO. 

5.4 Recommended RACT Level of Control

For reciprocating compressors, there are federal regulations and one state that requires 

the periodic replacement of reciprocating compressor packing. These regulations require the 

replacement of reciprocating compressor rod packing every 3 years or after 26,000 hours of 

operation. The NSPS also provides the alternative of routing rod packing emissions to a process 

via a closed vent system under negative pressure. 

As noted in section 5.3 of this chapter, the most significant volume of VOC emissions are 

associated with piston rod packing systems. We found that under the best conditions, regular rod 

packing replacement, when carried out approximately every three years, effectively controls 

emissions and helps prevent excessive rod wear. The cost of control for requiring the 

replacement of reciprocating packing at this frequency was estimated to be $1,132 per ton of 

VOC reduced without savings and $298 per ton of VOC reduced considering savings for 

gathering and boosting station compressors, and about $334 per ton of VOC reduced without 

savings and an overall net savings per ton of VOC reduced for the processing segment 

reciprocating compressors considering savings. Based on the emission reductions, costs 

(considering gas savings) and existing and currently implemented regulations that require the 

replacement of the reciprocating compressor packing every 36 months or after 26,000 hours of 

operation, we recommend this control option as RACT for reciprocating compressors in the 

production and processing segments (excluding compressors at the well site). We also 
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recommend that regulatory agencies provide operators the compliance alternative of routing rod 

packing emissions to a process via a closed vent system under negative pressure.

For centrifugal compressors, there are already federal, state and local regulations that 

require the capture and 95 percent control of emissions from wet seal fluid degassing systems 

from centrifugal compressors. Although dry seal systems have inherently low VOC emissions 

and the option of routing to a process has at least a 95 percent control efficiency, the replacement 

of wet seals with dry seals and routing to a process may not be technically feasible or practical 

options for some centrifugal compressors. The integration of a centrifugal compressor into an 

operation may require a certain compressor size or design that is not available in a dry seal 

model, and, in the case of capture of emissions with routing to a process, there may not be downstream equipment capable of handling a low pressure fuel source. As a result of our evaluation of 

the technical feasibility and practicality of existing available controls, we recommend RACT be

95 percent control of emissions from the wet seal degassing system, which can be achieved by

using a closed vent system and routing emissions to a combustor or routing the emissions back to 

the compressor or fuel line (routing to the process). For the processing segment, we assume that 

there is an existing combustion device on-site and the estimated cost of control would be about 

$183 per ton of VOC reduced for facilities to route emissions to the existing combustion device, 

or about $141 per ton of VOC reduced for facilities to route the captured emissions back to the 

compressor or fuel line. 

In summary, we recommend the following as RACT for compressors:

(1) RACT for Reciprocating Compressors Located Between the Wellhead and Point of 

Custody Transfer to the Natural Gas Transmission and Storage Segment (Excludes the 

Well Site): We recommend that each reciprocating compressor reduce VOC emissions by

replacing the rod packing after 26,000 hours of operation or 36 months since the last rod 

packing replacement. We also recommend that an alternative be provided to allow 

routing of rod packing emissions to a process via a closed vent system under negative 

pressure in lieu of the specified rod packing replacement periods.

(2) RACT for Centrifugal Compressors Using Wet Seals Located Between the Wellhead and 

Point of Custody Transfer to the Natural Gas Transmission and Storage Segment 

(Excludes the Well Site): We recommend that each centrifugal compressor using wet 
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seals reduce VOC emissions from each wet seal fluid gassing system by reducing VOC 

emissions by 95 percent. 

5.5 Factors to Consider in Developing Compressor Compliance 

Procedures 

5.5.1 Reciprocating Compressor Compliance Recommendations

In order to ensure and demonstrate compliance with the recommended RACT for 

reciprocating compressors, we recommend that regulatory agencies require facilities to maintain 

a record of the date of the most recent reciprocating compressor rod packing replacement, 

monitor and keep records of the number of hours of operation and/or track the number of months 

since the last rod packing replacement for each reciprocating compressor (to meet the 

requirement that the packing is changed out before the total number of hours of operation 

reaches 26,000 hours or the number of months since the most recent rod packing replacement 

reaches 36 months) and maintain records of instances where the reciprocating compressor was 

not operated in compliance with RACT. This may require the installation of an operating hours 

meter on the engine to track the number of hours of operation. We also recommend that 

regulatory agencies require annual reports of the cumulative hours of operation or number of 

months since packing replacement for each reciprocating compressor and instances when there 

were deviations where the reciprocating compressor was not operated in compliance with the 

recommended RACT. 

For applications in which operators choose to opt for the alternative of routing of rod 

packing emissions to a process via a closed vent system under negative pressure, we recommend 

that regulatory agencies require facilities to maintain records of the date of installation of a rod 

packing emissions collection system and closed vent system and maintain records of instances of 

deviations in cases where the reciprocating compressor was not operated in compliance with 

requirements. We also recommend that regulatory agencies require annual reports for each 

reciprocating compressor complying with this option indicating when there were deviations 

where the reciprocating compressor was not operated in compliance with the recommended 

RACT. We include closed vent system design and compliance measure recommendations in 

section 5.5.4 of this chapter.
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The appendix to this document presents example model rule language that incorporates 

compliance elements recommended in this section that states may choose to use in whole or in 

part.

5.5.2 Centrifugal Compressor Equipped with a Wet Seal Recommendations

In order to ensure that VOC emissions are reduced by at least 95 percent (the 

recommended RACT level of control) from a centrifugal compressor equipped with wet seals 

when using a control device or other control measure (such as routing to a process), the 

centrifugal compressor should be equipped with a cover that is connected through a closed vent 

system that routes emissions to the control device (or process) that meets the RACT level of 

control. Recommended cover and closed vent system design and operation measures are 

specified in sections 5.5.3 and 5.5.4. Recommended control device operation and monitoring 

provisions for specified controls to assure compliance are presented in section 5.5.5. 

The appendix of this document presents example model rule language that incorporates 

compliance elements recommended in this section that states may choose to use in whole or in 

part.

5.5.3 Recommendations for Cover Design

The cover and all openings on the cover (e.g., access hatches, sampling ports, pressure 

relief valves and gauge wells) should form a continuous impermeable barrier over the entire 

surface area of the liquid in the wet seal fluid degassing system. Each cover opening should be 

secured in a closed, sealed position (gasket lid or cap) whenever material is in the unit except 

when it is necessary to open as follows:

(1) To add material to or remove material from the unit (including openings necessary to 

equalize or balance the internal pressure of the unit following changes in the level of 

material in the unit); 

(2) To inspect or sample the material in the unit; 

(3) To inspect, maintain, repair, or replace equipment located in the unit; or

(4) To vent liquids, gases or fumes from the unit through a closed-vent system designed and 

operated in accordance specified control device requirements (see section 5.5.5) or to a 

process.

It is recommended that regulatory agencies require olfactory, visual and auditory

inspections of covers for defects that could result in air emissions on a monthly basis. We 
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recommend regulatory agencies require that any detected defects be repaired as soon as 

technically feasible to minimize emissions (and prior to the end of the next shutdown).

5.5.4 Recommendations for Closed Vent Systems 

The closed vent system should be designed and operated with no detectable emissions 

(which can be monitored by monthly olfactory, visual and auditory inspections) and should be 

operating at least 95 percent of the year. We recommend regulatory agencies require that any

detected defects be repaired as soon as technically feasible to minimize emissions (and prior to 

the end of the next shutdown).

With the exception of low leg drains, high point bleeds, analyzer vent, open-ended valves 

and safety devices, if the closed vent system contains one or more bypass devices that could be 

used to divert all or a portion of the gases, vapors, or fumes from entering the control device or 

to a process, regulatory agencies should require that owners or operators either:

(1) Install, calibrate, maintain and operate a flow indicator at the inlet to the bypass device 

that could divert the stream away from the control device or process to the atmosphere 

that sounds an audible and visual alarm, or, initiates notification via remote alarm to the 

nearest field office, when the bypass device is open such that the stream is being, or could 

be, diverted away from the control device or process to the atmosphere; or 

(2) Secure the bypass device valve installed at the inlet to the bypass device in the nondiverting position using a car-seal or a lock-and-key type configuration. We recommend 

requiring bypass devices to be equipped with flow indicators that sound an alarm when 

the stream is diverted away from the control device or process to the atmosphere and that 

records be maintained of times when the alarm sounds.

5.5.5 Recommendations for Control Device Operation and Monitoring 

If a control device is used to comply with the recommended 95 percent VOC emission 

reduction RACT level of control, we advise that the device be required to operate at all times 

when gases, vapors, and fumes are vented from the wet seal fluid degassing system through the 

closed vent system to the control device. The following paragraphs present select emission

control options and suggested operation and monitoring requirements, as appropriate to assure 

compliance with the recommended RACT level of control.
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Enclosed Combustion Devices

If an enclosed combustion device (e.g., thermal vapor incinerator, catalytic vapor 

incinerator, boiler, or process heater) is used to meet the 95 percent VOC emission reduction 

RACT level of control, it should be designed to reduce the mass content of VOC emissions by 95 

percent or greater; and (1) maintained in a leak free condition, (2) installed and operated with a 

continuous burning pilot flame, and (3) operated with no visible emissions. 

We recommend that the visible emissions test (using section 11 of EPA Method 22, 40 

CFR part 60, appendix A-7) be performed at least once every calendar month. If a combustion 

device fails the visible emissions test, sources should be required to follow manufacturer’s repair 

instructions, if available, or best combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant operation. We recommend all 

inspection, repair and maintenance activities for each unit be recorded in a maintenance and 

repair log that can be made available for inspection. Following return to operation from 

maintenance or repair activity, each device should be required to pass a Method 22, 40 CFR part 

60, appendix A-7 visual emissions test. 

We recommend regulatory agencies require that sources meeting the 95 percent VOC 

emission reduction RACT level of control by routing emissions to a combustion device conduct 

performance tests and/or design analyses that demonstrate that the combustion device being used 

meets the required 95 percent VOC emission reduction RACT level of control (see section F of 

the appendix to this document for performance testing procedures for control devices that we 

recommend be used to demonstrate performance requirements).

Routing to a Process

Routing to a process would entail routing emissions via a closed vent system to any

enclosed portion of a process unit where the emissions are predominantly recycled, consumed in 

the same manner as a material that fulfills the same function in the process, transformed by 

chemical reaction into materials that are not regulated materials, incorporated into a product, or

recovered. VRUs and flow lines that “route emissions to a process” would be considered part of 

the process and would not be considered control devices that are subject to standards, but the 

closed vent design, operation and monitoring requirements specified in sections 5.5.3 and 5.5.4 

would apply.
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Pneumatic Controllers

6.0 PNEUMATIC CONTROLLERS

The oil and natural gas industry uses a variety of process control devices to operate 

valves that regulate pressure, flow, temperature, and liquid levels. Most instrumentation and 

control equipment falls into one of three categories: (1) pneumatic; (2) electrical; or (3) 

mechanical. Of these, only pneumatic devices are direct sources of air emissions. Pneumatic 

controllers are pneumatic devices used throughout the oil and natural gas industry as part of the 

instrumentation to control the position of valves and may be actuated using pressurized natural 

gas (natural gas-driven) or may be actuated by another means such as a pressurized gas other 

than natural gas, solar, or electric. This chapter provides a description of pneumatic controllers 

that are used in the oil and natural gas industry, including their function and associated 

emissions. This chapter also provides control techniques used to reduce VOC emissions from 

these pneumatic controllers, along with costs and emission reductions. Finally, this chapter 

provides a discussion of our recommended RACT and the associated VOC emission reductions 

and costs for pneumatic controllers.

6.1 Applicability

For the purposes of this guideline, a pneumatic controller is an automated instrument 

used to maintain a process condition such as liquid level, pressure, delta-pressure and 

temperature. The emissions and emission controls discussed herein would apply to natural-gasdriven pneumatic controllers in the oil and natural gas industry located from the wellhead to a 

natural gas processing plant (including the natural gas processing plant) or from the wellhead to 

the point of custody transfer to an oil pipeline.
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6.2 Process Description and Emission Sources

6.2.1 Process Description71

Natural gas-driven pneumatic controllers come in a variety of designs for a variety of 

uses. For the purposes of this guideline, they are characterized primarily by their emissions 

characteristics: 

(1) Continuous bleed pneumatic controllers are used to modulate flow, liquid level, or 

pressure, and gas is vented continuously at a rate that may vary over time. Continuous 

bleed controllers are further subdivided into two types based on their bleed rate: 

a. Low bleed, having a bleed rate of less than or equal to 6 standard cubic feet per 

hour (scfh).

b. High bleed, having a bleed rate of greater than 6 scfh. 

(2) Intermittent bleed or snap acting pneumatic controllers release gas only when they open 

or close a valve or as they throttle the gas flow. 

(3) Zero bleed pneumatic controllers do not bleed natural gas to the atmosphere. These 

natural gas-driven pneumatic controllers are self-contained devices that release gas to a 

downstream pipeline instead of to the atmosphere. 

Pneumatic controllers often make use of available high-pressure natural gas to operate 

valves. The supply gas pressure is modulated by a process condition, and then flows to the valve 

controller where the signal is compared with the process set-point to adjust gas pressure in the 

valve actuator. In these natural gas-driven pneumatic controllers, natural gas may be released 

intermittently with every actuation of the valve. In other designs, natural gas may be released 

continuously from the valve control pilot. The rate at which the continuous release occurs is 

referred to as the bleed rate. Bleed rates are dependent on the design and operating characteristics 

of the device. Similar designs will have similar steady-state rates when operated under similar 

conditions. It is our understanding that self-contained devices that release natural gas to a 

downstream pipeline instead of to the atmosphere have no emissions. “Closed loop” systems are 

 

71 U.S. Environmental Protection Agency. Lessons Learned: Options for Reducing Methane Emissions From 

Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas STAR Program. 

Washington, DC. October 2006.
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applicable only in instances with very low pressure72 and may not be suitable to replace many

applications of continuous or intermittent bleed pneumatic devices. Therefore, this guideline 

does not address these self-contained devices further.

Intermittent controllers are devices that only emit gas during actuation and do not have 

a continuous bleed rate. The actual amount of emissions from an intermittent controller is 

dependent on the amount of natural gas vented per actuation and how often it is actuated. Bleed

devices also vent an additional volume of gas during actuation, in addition to the controller’s

bleed stream. Since actuation emissions serve the controller’s functional purpose and can be 

highly variable, the emissions characterized for high-bleed and low-bleed devices in this 

analysis (as described in section 6.2.2) account for only the continuous flow of emissions (i.e., 

the bleed rate) and do not include emissions directly resulting from actuation. Intermittent 

controllers are assumed to have zero bleed emissions. For most applications (but not all), 

intermittent controllers serve functionally different purposes than bleed devices and would not 

be a technically practical control option for all continuous bleed controllers. It is assumed

intermittent, or no-bleed, controllers meet the definition of a low-bleed.

As previously indicated, not all pneumatic controllers are natural gas-driven. At sites with 

a continuous and reliable source of electricity, controllers can be actuated by an instrument air 

system that uses compressed air instead of natural gas. These sites may also use mechanical or 

electrically powered pneumatic controllers. In some instances, solar-powered controllers may be 

feasible. Because these devices are not natural gas-driven, they do not directly release natural gas 

or VOC. However, electrically powered systems have energy impacts, with associated secondary

impacts related to generation of the electrical power required to drive the instrument air 

compressor system. To our knowledge natural gas processing plants are the only facilities in the 

oil and natural gas industry that are likely to have electrical service sufficient to power an 

instrument air system, and that most existing natural gas processing plants use instrument air 

instead of natural gas-driven devices.73

 

72 Memorandum to Bruce Moore, U.S. Environmental Protection Agency, from Denise Grubert, EC/R Incorporated. 

Meeting Minutes from EPA Meeting with the American Petroleum Institute (API). October 2010.

73 U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic 

Devices. EPA-600/R/-96-080k. June 1996.
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6.2.2 Emissions Data

6.2.2.1 Summary of Major Studies and Emissions

In the evaluation of the emissions from pneumatic controllers and the potential options 

available to reduce these emissions, numerous studies were consulted. Table 6-1 lists these 

references with an indication of the type of relevant information contained in each reference. In 

addition to these sources, we evaluated the peer reviewer and public comments received on the 

EPA’s white paper, “Oil and Natural Gas Sector Pneumatic Devices.”74

Table 6-1. Major Studies Reviewed for Consideration of Emissions and Activity Data

Report Name Affiliation Year of 

Report

Activity 

Factors

Emissions 

Data

Control 

Options 

Greenhouse Gas 

Reporting Program 

(Annual Reporting; 

Current Data 

Available for 2011-

2013)a

EPA 2014 Facility-Level X X

Inventory of 

Greenhouse Gas 

Emissions and Sinks: 

1990-2012b

EPA 2014 Nationwide/

Regional X

Methane Emissions 

from the Natural Gas 

Industryc

EPA/GRI 1996 Nationwide X

Methane Emissions 

from the Petroleum 

Industryd

EPA/GRI 1996 Nationwide X

Methane Emissions 

from the U.S. Oil 

Industrye

EPA 1999 Nationwide X

Oil and Gas Emission 

Inventories for 

Western Statesf

WRAP 2005 Regional X

Natural Gas STAR 

Programg EPA 2000- 2010 Voluntary X X

Measurements of 

Methane Emissions 

from Natural Gas 

Production Sites in 

the United Statesh

Multiple 

Affiliations, 

Academic 

and Private

2013 Nationwide X

 

74 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Pneumatic Devices. Report for Oil and 

Natural Gas Sector Pneumatic Devices Review Panel. Office of Air Quality Planning and Standards (OAQPS). 

April 2014. Available at http://www.epa.gov/airquality/oilandgas/2014papers/20140415pneumatic.pdf
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Report Name Affiliation Year of 

Report

Activity 

Factors

Emissions 

Data

Control 

Options 

Determining Bleed 

Rates for Pneumatic 

Devices in British 

Columbiai 

The Prasino 

Group 2013 British Columbia X

Air Pollutant 

Emissions from the 

Development, 

Production, and 

Processing of 

Marcellus Shale 

Natural Gasj

Carnegie 

Mellon 

University

2014

Regional 

(Marcellus 

Shale)

X

Economic Analysis of 

Methane Emission 

Reduction 

Opportunities in the 

U.S. Onshore Oil and 

Natural Gas 

Industriesk

ICF 

International 2014 Nationwide X X

a. U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas

Industry: Background Technical Support Document. Climate Change Division. Washington, DC. 

b. U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions from Natural Gas Systems.

Greenhouse Gas Inventory: Emission and Sinks 1990-2012. Washington, DC. And U.S Environmental Protection Agency.

Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 

1990-2012. Washington, DC.

c. U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical Report.

EPA-600/R-96-080b. June 1996; U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas

Industry, Vol. 3: General Methodology. EPA-600/R-96-080c. June 1996; U.S. Environmental Protection Agency/GRI.

Methane Emissions from the Natural Gas Industry, Vol. 5: Activity Factors. EPA-600/R-96-080e. June 1996; and U.S. 

Environmental Protection Agency. Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic Devices. EPA600/R-96-080k. June 1996.

d. U.S. Environmental Protection Agency/GRI. Methane Emissions from the U.S. Petroleum Industry. Draft Report. June 14, 

1996.

e. ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry. Prepared for the U.S. Environmental Protection

Agency. 1999.

f. ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States. Prepared for Western

Governors Association. December 27, 2005.

g. U.S. Environmental Protection Agency. Lessons Learned: Options for Reducing Methane Emissions From Pneumatic Devices

in the Natural Gas Industry. Office of Air and Radiation: Natural Gas STAR. Washington, DC. October 2006.

h. Memorandum to Bruce Moore, U.S. EPA from Heather Brown, EC/R. Composition of Natural Gas for Use in the Oil and 

Natural Gas Sector Rulemaking. July 2011.

i. U.S. Environmental Protection Agency. Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air. Office of Air 

and Radiation: Natural Gas Star. Washington, DC. 2006.

j. U.S. Environmental Protection Agency. Pro Fact Sheet No. 301. Convert Pneumatics to Mechanical Controls. Office of Air

and Radiation: Natural Gas Star. Washington, DC. September 2004.

k. Canadian Environmental Technology Advancement Corporation (CETAC)-WEST. Fuel Gas Best Management Practices:

Efficient Use of Fuel Gas in Pneumatic Instruments. Prepared for the Canadian Association of Petroleum Producers. May 2008

6.2.2.2 Representative Pneumatic Controller Device Emissions

For purposes of this guideline, continuous bleed pneumatic controllers are classified into 

two types based on their emissions rates: (1) high bleed controllers and (2) low bleed controllers. 
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A controller is considered to be high bleed when the continuous bleed emissions are in excess of 

6 scfh, while low bleed devices bleed at a rate less than or equal to 6 scfh.75

In support of the development of the 2012 NSPS, and these guidelines, we consulted 

information in the appendices of the Natural Gas STAR Lessons Learned document on 

pneumatic devices, subpart W of the GHGRP, the GHG Inventory, as well as pneumatic 

controller vendor information used during the development of the 2012 NSPS.76 The data 

obtained from vendors included emission rates, costs, and any other pertinent information for 

each pneumatic controller model (or model family). All pneumatic controllers that a vendor 

offered were itemized and inquiries were made into the specifications of each device and 

whether it was applicable to oil and natural gas operations. High bleed and low bleed devices 

were differentiated using the 6 scfh threshold.

Although, by definition, a low bleed device can emit up to 6 scfh, through vendor 

research, a typical low bleed device available currently on the market emits lower than the 

maximum rate allocated for the device type. Specifically, low bleed devices on the market today

have bleed rates from 0.2 scfh up to 5 scfh. Similarly, the available bleed rates for a high bleed

device vary significantly from venting as low as 7 scfh to as high as 100 scfh.77,78 While the 

vendor data provides useful information on specific makes and models, it did not yield sufficient 

information about the prevalence of each model type in the population of devices in the oil and 

natural industry, which is an important factor in developing a representative emission factor. 

Therefore, in support of these guidelines, we have determined that the best available emission

estimates for pneumatic controllers in the production segment are from the GHGRP. For the 

natural gas processing segment, we determined that the quantified representative methane 

 

75 The classification of high bleed and low bleed devices originated from a report by Pacific Gas & Electric (PG&E)

and the Gas Research Institute (GRI) in 1990 titled “Unaccounted for Gas Project Summary Volume.” This

classification was adopted for the October 1993 Report to Congress titled “Opportunities to Reduce Anthropogenic

Methane Emissions in the United States”. As described on page 2-16 of the report, “devices with emissions or ‘bleed 

rates’ of 0.1 to 0.5 cubic feet per minute are considered to be ‘high bleed’ types (PG&E 1990).” This range of bleed

rates is equivalent to 6 to 30 cubic feet per hour.

76 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Production, Transmission, and Distribution – Background Technical Support Document for Proposed 

Standards. July 2011. EPA Document Number EPA-453/R-11-002.

77 U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the Petroleum and Natural

Gas Industry: Background Technical Support Document. Climate Change Division. Washington, DC. November

2010.

78 All rates are listed at an assumed supply gas pressure of 20 psig.
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emissions from a continuous bleed pneumatic controller based on natural gas emission rates 

presented in Volume 12 of the EPA/GRI report used in the 2012 NSPS TSD is the best available 

emissions information79. 

The basic approach used for this analysis of emissions from pneumatic controllers was to 

first approximate the natural gas emissions from an average high bleed and low bleed pneumatic 

controller in the production and processing segments and then estimate methane and VOC 

emissions using a representative gas composition from the 2011 Gas Composition Memorandum.

A bleed rate of 1.39 scfh was used for a low bleed controller, and a bleed rate of 37.3 scfh was 

used for a high bleed controller. The specific gas composition ratio used for the production and 

processing segments was 0.278 pounds VOC per pound methane. Table 6-2 summarizes the 

estimated bleed emissions for a representative pneumatic controller by industry segment (for 

production and processing segments) and device type.

Table 6-2. Average Emission Rates for High Bleed and Low Bleed Pneumatic Controllers 

in the Oil and Natural Gas Industrya

Industry Segment

High Bleed

(tpy)

Low Bleed

(tpy)

CH4 VOC CH4 VOC

Oil and Natural Gas

Productionb 5.3 1.47 0.2 0.06

Natural Gas Processingd1.00 0.28 1.0 0.28

a. The conversion factor used in this analysis is 1 Mcf of methane is equal to 0.0208 tons methane.

b. Natural gas production methane emissions are derived from the GHGRP (subpart W). 

c. Oil production methane emissions are derived from the GHGRP (subpart W). It is assumed only continuous bleed 

devices are used in oil production. 

d. Natural gas processing segment methane emissions are derived from Volume 12 of the 1996 EPA/GRI report. 

Emissions from devices in the processing segment were determined based on data available for snap-acting and 

continuous bleed devices. Further distinction between high and low bleed could not be determined based on 

available data. For the natural gas processing segment, it is assumed that existing natural gas plants have already 

replaced pneumatic controllers with other types of controls (i.e., an instrument air system) and any high bleed

devices that remain are safety related.

For the natural gas processing segment, this analysis assumes that existing natural gas 

plants have already replaced pneumatic controllers with other types of controls (i.e., an 

instrument air system) and any high bleed devices that remain are safety related. 

 

79 GRI/EPA Research and Development. Methane Emissions from the Natural Gas Industry; Volume 12: Pneumatic 

Devices. (1996) EPA-600/R-96-0801. Table 4-11, page 56. epa.gov/gasstar/tools/related.html
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6.3 Available Controls and Regulatory Approaches

6.3.1 Available VOC Emission Control Options

Although pneumatic controllers have relatively small emissions individually, due to the 

large population of these devices the cumulative VOC emissions for the industry are significant. 

We are not aware of any add-on controls that are or can be used to reduce VOC emissions from 

gas-driven pneumatic controllers. The following sections provide a summary of options for 

reducing VOC emissions from pneumatic controllers including: (1) replacing high bleed

controllers with low bleed controllers or zero bleed controllers, (2) driving controllers with 

instrument air rather than natural gas, using non-gas-driven controllers, and (3) enhanced 

maintenance. 

Sections 6.3.1.1 and 6.3.1.2 discuss the control of VOC emissions by replacing a high 

bleed device with a low bleed device, and driving controllers with instrument air rather than 

natural gas, including the estimated costs of these options. Given applicability, efficiency and the 

expected costs, other options (i.e., mechanical controls and enhanced maintenance) are only 

briefly discussed in sections 6.3.1.3 and 6.3.1.4. 

6.3.1.1 Install a Low bleed Device in Place of a High bleed Device

Description

As discussed previously, low bleed controllers generally provide the same operational 

function as a high bleed controller, but have lower continuous bleed emissions. 

Control Effectiveness

We estimate on average that 1.41 tons of VOC will be reduced annually per device in the 

production segment from installing a low bleed device in place of a high bleed device. There are 

certain situations in which replacing and retrofitting devices are not feasible, such as instances 

where a minimal response time is needed, cases where large valves require a high bleed rate to 

actuate, or a safety isolation valve is involved. Based on criteria provided by the Natural Gas 

STAR Program, we assumed about 80 percent of high bleed devices can be replaced with low 

bleed devices throughout the production segment. 

Applicability of low bleed controllers may depend on the function carried out by the 

controller. Low bleed pneumatic controllers may not be applicable for replacement of high bleed

devices because a process condition may require a fast or precise control response minimize 
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deviation from the desired set point. A slower acting low bleed controller could potentially result 

in damage to equipment and/or become a safety issue because it may not be able to respond as 

quickly as a high bleed controller. An example of this is a compressor where pneumatic 

controllers may monitor the suction and discharge pressure and actuate a recycle when one or the 

other is out of the specified target range. Other scenarios for fast and precise control include 

transient (non-steady state) situations where a gas flow rate may fluctuate widely or 

unpredictably. This situation requires a responsive high bleed device to ensure that the gas flow 

can be controlled in all situations. Temperature and level controllers are typically present in 

control situations that are not prone to fluctuate as widely or where the fluctuation can be readily 

and safely accommodated by the equipment. Therefore, such processes can typically 

accommodate control from a low bleed device, which is slower-acting and less precise. 

Cost Impacts

Costs were based on vendor research as a result of updating and expanding upon the 

information given in the appendices of the Natural Gas STAR Lessons Learned document on 

pneumatic controllers.81 As Table 6-3 indicates, the average cost for a low bleed pneumatic 

controller is $2,698, while the average cost for a high bleed pneumatic controller is $2,471.82 In 

order to analyze cost impacts, the average cost to install a new low bleed pneumatic controller 

was annualized for a 15 year period using a 7 percent interest rate. This equates to annualized 

costs of around $271 per low bleed device for the production segment. 

Table 6-3. Cost Projections for Representative Pneumatic Controllersa

Device

Minimum 

Cost 

($2012)

Maximum 

Cost 

($2012)

Average Cost 

($2012)

High Bleed Controller $387 $7,398 $2,471

Low Bleed Controller $554 $9,356 $2,698

a. 201l NSPS TSD 2008 dollars converted to 2012 dollars using the Federal Reserve Economic Data GDP Price 

Deflater (5.69 percent). During the development of the 2012 NSPS, major pneumatic controller vendors were 

surveyed for costs, emission rates, and any other pertinent information.

 

81 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Options for Reducing 

Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas 

STAR Program. Washington, DC. October 2006.

82 Costs are estimated in 2012 U.S. Dollars.
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Monetary savings associated with retaining natural gas that would have been emitted was 

estimated based on a natural gas value of $4.00 per Mcf.83 The use of a low bleed pneumatic 

controller is estimated to reduce methane emissions by 5.1 tpy (245 Mcf/yr) (using the 

conversion factor of 0.0208 tons methane per 1 Mcf) over the use of a high bleed pneumatic 

controller. Assuming natural gas in the production segment is 82.8 percent methane by volume, 

this equals 296 Mcf natural gas recovered per year. Therefore, the value of recovered natural gas 

from one pneumatic controller in the production segment is approximately $1,184. Table 6-4 

presents the estimated cost of control per ton of VOC reduced for replacing a high bleed

pneumatic controller with a new low bleed pneumatic controller in the production segment of the 

oil and natural gas industry.

Table 6-4. VOC Cost of Control for Replacing an Existing High Bleed Pneumatic 

Controller with a New Low Bleed Pneumatic Controller

Segment

Average

Capital 

Costs per 

Unit 

($2012)a,c

Total Annual 

Costs per Unit 

($2012/yr)b,c

VOC Cost of 

Control

($2012/ton)c

Without 

Savings

With 

Savings

Without 

Savings

With 

Savings

Oil and Natural Gas Production $2,698 $296 ($886) $210 ($627)

a. Average capital costs of a low bleed device as summarized in Table 6-3.

b. Annualized costs assume a 7 percent interest rate over a 15 year equipment lifetime. 

c. Cost data from the 2011 TSD converted to 2012 dollars using the Federal Reserve Economic Data GDP Price Deflater 

(5.69 percent).

 

83 U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price. Energy Information 

Administration. Natural Gas Navigator. Retrieved online on 12 Dec 2010 at 

http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm
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6.3.1.2 Instrument Air Systems

Description

The major components of an instrument air conversion project include the compressor, 

power source, dehydrator, and volume tank. The following is a description of each component as 

described in the Natural Gas STAR document, “Lessons Learned: Convert Gas Pneumatic 

Controls to Instrument Air”:

84

(1) Compressors used for instrument air delivery are available in various types and sizes, 

from centrifugal (rotary screw) compressors to reciprocating piston (positive 

displacement) types. The size of the compressor depends on the size of the facility, the 

number of control devices operated by the system, and the typical bleed rates of these 

devices. The compressor is usually driven by an electric motor that turns on and off, 

depending on the pressure in the volume tank. For reliability, a full spare compressor is 

normally installed. A minimum amount of electrical service is required to power the 

compressors.

(2) A critical component of the instrument air control system is the power source required to 

operate the compressor. Since high-pressure natural gas is abundant and readily available, 

natural gas pneumatic systems can run uninterrupted on a 24-hour, 7-day per week 

schedule. The reliability of an instrument air system, however, depends on the reliability

of the compressor and electric power supply. Most large natural gas plants have either an 

existing electric power supply or have their own power generation system. For smaller 

facilities and in remote locations, however, a reliable source of electric power can be 

difficult to assure. In some instances, solar-powered battery-operated air compressors can 

be cost effective for remote locations, which reduce both VOC emissions and energy

consumption. Small natural gas-driven fuel cells are also being developed.

(3) Dehydrators, or air dryers, are also an integral part of the instrument air compressor 

system. Water vapor present in atmospheric air condenses when the air is pressurized and 

cooled, and can cause a number of problems to these systems, including corrosion of the 

instrument parts and blockage of instrument air piping and controller orifices. 

 

84 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Convert Gas 

Pneumatic Controls to Instrument Air. Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. 

2006.
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(4) The volume tank holds enough air to allow the pneumatic control system to have an 

uninterrupted supply of high pressure air without having to run the air compressor 

continuously. The volume tank allows a large withdrawal of compressed air for a short 

time, such as for a motor starter, pneumatic pump, or pneumatic tools without affecting 

the process control functions.

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

any of the parts of the pneumatic controller. The use of instrument air eliminates natural gas 

emissions from natural gas-driven pneumatic controllers. All other parts of a natural gas 

pneumatic system will operate the same way with instrument air as they do with natural gas. The 

conversion of natural gas pneumatic controllers to instrument air systems is applicable to all 

natural gas facilities with electrical service available. Figure 6-1 illustrates a diagram of a natural 

gas pneumatic control system.85 Figure 6-2 illustrates a diagram of a compressed instrument air 

control system.

Control Effectiveness 

The use of instrument air eliminates natural gas emissions from the pneumatic 

controllers; however, the system is only applicable in locations with access to a sufficient and 

consistent supply of electrical power. Instrument air systems are also usually installed at facilities 

where there is access to high Btu gas, a high concentration of pneumatic control valves and the 

presence of an operator that can ensure the system is properly functioning.86

For natural gas processing plants, we believe that instrument air systems are typically 

used to power pneumatic controllers and that any natural gas-driven pneumatic controllers in use 

are required for safety and functional reasons. The use of an instrument air system would reduce 

VOC emissions from a natural gas-driven pneumatic controller by 100 percent. 

 

85 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Convert Gas 

Pneumatic Controls to Instrument Air. Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. 

2006.

86 Ibid.
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Cost Impacts

Instrument air conversion requires additional equipment to properly compress and control 

the pressurized air. The size of the compressor depends on the number of control loops present at 

a location. A control loop consists of one pneumatic controller and one control valve. The 

volume of compressed air supply for the pneumatic system is equivalent to the volume of gas 

used to run the existing instrumentation, adjusted for air losses during the drying process. The 

current volume of gas usage can be determined by direct metering if a meter is installed. 

Otherwise, an alternative rule of thumb for sizing instrument air systems is one cubic foot per 

minute (cfm) of instrument air for each control loop. As the system is powered by electric 

compressors, the system requires a constant source of electrical power and a back-up system to 

Figure 6-1. Natural Gas Pneumatic Control System
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Figure 6-2. Compressed Instrument Air Control System

operate the controllers in the event of interruption of the electrical supply. Table 6-5 outlines 

three different sized instrument air systems including the compressor power requirements, the 

flow rate provided from the compressor, and the associated number of control loops. 

Table 6-5. Compressor Power Requirements and Costs for Representative Instrument Air 

Systemsa

Compressor Power Requirementsb Flow Rate

(cfm)

Control Loops

(Loops/Compressor)

Power Costs 

($/yr)

Size of Unit Hp kW

Small 10 13.3 30 15 $7,758

Medium 30 40 125 63 $23,332

Large 75 100 350 175 $58,329

a. Based on rules of thumb stated in the Natural Gas STAR document, Lessons Learned: Convert Gas Pneumatic Controls to 

Instrument Air. Natural Gas STAR Program. Washington, DC. 2006.

b. Power is based on the operation of two compressors operating in parallel (each assumed to be operating at full capacity 50 

percent of the year).

The primary costs associated with conversion to instrument air systems are the initial 

capital expenditures for installing compressors and the related equipment and operating costs for 

electrical energy to power the compressor motor. This equipment includes a compressor, a power 

source, a dehydrator, gas supply piping, control instruments, valve actuators and a storage vessel. 

The total cost, including installation and labor, of three representative sizes of compressors were 
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evaluated based on assumptions found in the Natural Gas STAR document, “Lessons Learned: 

Convert Gas Pneumatic Controls to Instrument Air” and are summarized in Table 6-6.87

For new natural gas processing plants, the cost-effectiveness of the three representative 

instrument air system sizes was evaluated in the 2015 NSPS TSD based on the emissions 

mitigated from the number of control loops the system can provide and not on a per device basis. 

This approach was chosen because we assume new processing plants will need to provide 

instrumentation of multiple control loops and size the instrument air system accordingly. Table 

6-7 summarizes the natural gas processing segment cost of control per ton of VOC reduced for 

three sizes of representative instrument air systems.

For existing natural gas processing plants, it is our understanding that these plants have 

already upgraded to instrument air unless the function has a specific need for a high bleed

pneumatic controller, which would most likely be safety related. The cost of converting the 

 

87 Ibid.
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Table 6-6. Estimated Capital and Annual Costs of Representative Instrument Air Systems ($2012)

Instrument 

Air System 

Size

Compressor Tank Air Dryer

Total 

Capital 

Costs

a

Annualized 

Capital 

Costs

b

Labor Cost Total Annual 

Costsc

Annualized Costs

of Instrument Air 

System

Small $3,987 $797 $2,391 $17,938 $2,553 $1,410 $9,168 $11,721

Medium $19,928 $2,391 $7,173 $77,716 $11,065 $4,580 $27,911 $38,976

Large $35,071 $4,783 $15,941 $143,476 $20,428 $6,340 $64,669 $85,097

a. Total Capital Cost includes the cost for two compressors, two tanks, an air dryer and installation. Installation costs are assumed to be equal to 1.5 times the cost of capital. 

Equipment costs were derived from the 2012 NSPS TSD. 

b. These costs have been converted to 2012 dollars (from 2008 dollars) using the Federal Reserve Economic Data GDP Price Deflater (Change in GDP: Implicit Price Deflator from 

2008 to 2012 (5.69 percent).88

c. The annualized costs were estimated using a 7 percent interest rate and 10 year equipment life. Annual costs include the cost of electrical power as listed in Table 6-5 and labor.

Table 6-7. Cost of Control of Representative Instrument Air Systems in the Natural Gas Processing Segment ($2012)

System Size

Number of 

Control 

Loops

VOC Annual 

Emission 

Reduction

(tpy)a

Value of

Product 

Recovered

($2012/year)b

Annualized Costs of 

System

VOC Cost of Control

($2012/ton)

Without 

Savings

With 

Savings

Without 

Savings

With 

Savings

Small 15 4.18 $3,485 $11,721 $8,236 $2,807 $1,970

Medium 63 17.5 $14,592 $38,976 $24,385 $2,223 $1,393

Large 175 48.7 $40,606 $85,097 $44,490 $1,747 $914

a. Based on the emissions mitigated from the entire system, which includes multiple control loops. 

 

88 U.S. Bureau of Economic Analysis. Gross Domestic Product: Implicit Price Deflator (GDPDEF], retrieved from FRED, Federal Reserve Bank of St. Louis. 

https://research.stlouisfed.org/fred2/series/GDPDEF/ March, 26, 2015.
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b. Value of recovered product assumes natural gas processing is 82.9 percent methane by volume. A natural gas price of $4 per Mcf was assumed.
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pneumatic controllers to instrument air includes the capital costs of $2,000 for the ductwork and 

annual costs of $285 (assuming a 10 year equipment life at 7% interest). The VOC cost of 

control for converting pneumatic controllers to instrument air for processing plants that already

have instrument air ranges from $6 to $68 per ton of VOC removed, depending on the size of the 

instrument air system. 

For natural gas processing, the cost of control of the three representative instrument air 

systems was evaluated based on the emissions mitigated from the number of control loops the 

system can provide and not on a per controller basis. This approach was chosen because we 

assume new processing plants will need to provide instrumentation for multiple control loops 

and size the instrument air system accordingly. We also assume that existing processing plants 

have already upgraded to instrument air unless the function has a specific need for a high bleed 

pneumatic controller, which would most likely be safety related. Table 6-7 summarizes the 

natural gas processing segment cost of control per ton of VOC reduced for three sizes of 

representative instrument air systems

6.3.1.3 Electrically Powered Systems in Place of Bleed Devices

Description

Mechanical controls have been widely used in the oil and natural gas industry. They

operate using a combination of levers, hand wheels, springs and flow channels with the most 

common mechanical control device being a liquid-level float to the drain valve position with 

mechanical linkages.89 Another device that is increasing in use is electrically powered controls. 

Small electrical motors (including solar powered) have been used to operate valves and have no 

VOC emissions. Solar powered control systems are driven by solar power cells that actuate 

mechanical devices using electric power. As such, solar cells require some type of back-up 

power or storage to ensure reliability. 

 

89 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Options for Reducing 

Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas

STAR Program. Washington, DC. October 2006.
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Control Effectiveness90

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

proximity to the process measurement. Mechanical systems may have difficulty handling larger 

flow fluctuations. Electrically powered valves are only reliable with a constant supply of 

electricity. These controllers can achieve a 100 percent reduction in VOC emissions where 

applicable.

Cost Impacts

Depending on supply of power, mechanical and solar power system costs can range from 

below $1,000 to $10,000 for an entire system.91

6.3.1.4 Enhanced Maintenance of Natural Gas-Driven Pneumatic Controllers

Manufacturers of pneumatic controllers indicate that emissions in the field can be higher 

than the reported gas consumption due to operating conditions, age, and wear of the device.93

Examples of circumstances or factors that can contribute to this increase include:94,95

 

90 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Convert Gas 

Pneumatic Controls to Instrument Air. Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. 

October 2006.

91 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Options for Reducing 

Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas

STAR Program. Washington, DC. October 2006.
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(1) Nozzle corrosion resulting in more flow through a larger opening;

(2) Broken or worn diaphragms, springs (e.g., spring broken that holds the supply pilot-plug 

on its seat), bellows, fittings (e.g., leaking tubing/tubing-fittings) and nozzles;

(3) Corrosives in the gas leading to erosion and corrosion of control loop internals;

(4) Improper installation;

(5) Lack of maintenance (maintenance includes replacement of the filter used to remove 

debris from the supply gas and replacement of O-rings and/or seals);

(6) Lack of calibration of the controller or adjustment of the distance between the flapper and 

nozzle; 

(7) Foreign material lodged in the pilot seat;

(8) Debris/deposits on vent pilot plug. Material on the vent pilot can allow the controller to 

exhaust gas during the activation cycle;

(9) Debris/deposits on the supply pilot plug. Material on the supply pilot can cause the 

introduction of gas while the vent is open; or

(10) Wear in the seal seat.

The EPA prepared a white paper titled “Oil and Natural Gas Sector Pneumatic Devices” 

in 2014, requesting specific comment on available emissions data for pneumatic devices. One of 

the comments received regarding data presented in “Measurements of Methane Emissions at 

Natural Gas Production Sites in the United States”96 was that the data set reported was 

dominated by extreme values. The commenter noted that the highest emitting controllers are 

simply controllers emitting at a large rate, regardless of their service or design type. These 

controllers can have high emissions because of factors, other than design, related to maintenance, 

malfunction, or defect.97

Maintenance of pneumatics can correct many of these problems and can be an effective 

method for reducing emissions. Cleaning and tuning, in addition to repairing leaking gaskets, 

 

93 Ibid.

94 Ibid.

95 American Petroleum Institute (API). Pneumatic Controllers. Webinar Prepared and Presented to the U.S. 

Environmental Protection Agency. March 25, 2014.

96 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Pneumatic Devices. Report for Oil and 

Natural Gas Sector Pneumatic Devices Review Panel Office of Air Quality Planning and Standards (OAQPS). April 

2014. Available at http://www.epa.gov/airquality/oilandgas/2014papers/20140415pneumatic.pdf. 

97 Allen, David. Comments Provided to the EPA on Oil and Natural Gas Sector Pneumatic Devices-Peer Review 

Document. University of Texas at Austin. June 2014.
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tubing fittings, and seals, can save 5 to 10 scfh per device. Eliminating unnecessary valve 

positioners can save up to 18 scfh per device.98

6.3.2 Existing Federal, State and Local Regulations

6.3.2.1 Federal Regulations that Specifically Require Control of VOC 

Emissions

Under the 2012 NSPS, new or modified continuous bleed natural gas-driven pneumatic 

controllers at natural gas processing plants are subject to a VOC emission limit of zero 

(equivalent to non-natural gas-driven pneumatic controllers). Continuous bleed natural gasdriven pneumatic controllers in the production segment must have a bleed rate of 6 scfh or less. 

6.3.2.2 State and Local Regulations that Specifically Require Control of VOC 

Emissions

States may have permitting restrictions on VOC emissions that apply to an emissions 

source as a result of an operating, NSR NA, or PSD permit (e.g., on a case-by-case basis) 

requirements based on air quality maintenance or improvement goals of an area. Permits specify

what construction is allowed, what emission limits must be met, and often how the source must 

be operated. To assure that sources follow the permit requirements, permits also contain 

monitoring, recordkeeping, and reporting requirements

For pneumatic controllers, Colorado and Wyoming have existing control requirements 

similar to those required under the 2012 NSPS. Other states have permitting and registration 

rules for controlling fugitive VOC emissions (which would include non-bleed emissions from 

pneumatic controllers). 

Colorado requires that no- or low bleed pneumatic controllers with a bleed rate of 6 scfh 

or less be installed for all new and existing applications (unless approved for use due to safety 

and/or process purposes) statewide (Regulation 7, XVIII.C.2). Where technically and 

economically feasible, Colorado requires no-bleed pneumatic controllers at facilities that are 

connected to the electric grid and using electricity to power equipment.

 

98 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Options for Reducing

Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas

STAR Program. Washington, DC. October 2006.
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Wyoming requires the installation of low- or no-bleed pneumatic controllers with a bleed 

rate of 6 scfh or less at all new facilities. Upon modification of facilities, new pneumatic 

controllers must be low- or no-bleed and existing controllers must be replaced with no- or low 

bleed controllers (at well site facilities only and not at natural gas processing plants).

Although some local rule requirements do not specifically require the control of VOC 

emissions from pneumatic controllers, local permit requirements (such as those required by the 

Bay Area Air Quality Management District) may require that a permit to operate applicant 

provide the number of high bleed and low bleed pneumatic devices in a permit application. 

Under some situations where facilities use high bleed devices, the permitting authority might 

require an owner or operator to provide device-specific bleed rates and supporting 

documentation for each high bleed device. In cases where high bleed devices must be used, the 

permitting authority may require that the facility conduct fugitive monitoring and/or implement 

control requirements under conditions of their permit to operate99.

6.4 Recommended RACT Level of Control

Sections 6.4.1 and 6.4.2 present the recommended RACT level of control/impacts for 

continuous bleed natural gas-driven pneumatic controllers located at natural gas processing 

plants and continuous bleed natural gas-driven pneumatic controllers located from the wellhead 

to the natural gas processing plant or point of custody transfer to an oil pipeline. 

6.4.1 Continuous Bleed Natural Gas-Driven Pneumatic Controllers Located at a 

Natural Gas Processing Plant

Based on our evaluation of available data obtained in the development of the 2012 NSPS, 

peer review comments received on the “Oil and Natural Gas Sector Pneumatic Devices” white 

paper, and existing regulations that control VOC emissions from pneumatic controllers, we 

recommend that VOC emissions from an individual continuous bleed natural gas-driven 

pneumatic controller located at a natural gas processing plant be controlled by RACT. As noted 

in section 6.3.2, both Colorado and Wyoming require either low- or no-bleed controllers (where 

a high bleed controller is defined as emitting at least 6 scfh); and the 2012 NSPS requires that 

 

99 Cheng, Jimmy. Permit Handbook. Chapter 3.5 Natural Gas Facilities and Crude Oil Facilities. Bay Area Air 

Quality Management District. September 16, 2013.
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new and modified individual continuous bleed pneumatic controllers at natural gas processing 

plants have a natural gas bleed rate of zero scfh (unless there are functional needs, including but 

not limited to response time, safety and positive actuation, requiring a bleed rate greater than 

zero scfh). For existing individual continuous bleed pneumatic controllers at natural gas 

processing plants, our RACT recommendation is that controllers have a natural gas bleed rate of 

zero scfh (unless there are functional needs, including but not limited to response time, safety 

and positive actuation, requiring a bleed rate greater than zero scfh). Our rationale for selecting a 

natural gas bleed rate of zero scfh (with functional and safety exceptions) for our recommended 

RACT is based on the ability of most natural gas processing plants to install and utilize an 

instrument air system. As discussed in section 6.3.1.2 of this chapter, by using an instrument air 

system, compressed air may be substituted for natural gas in pneumatic systems without altering 

any of the parts of the pneumatic controller. Therefore, the use of instrument air eliminates 

natural gas and VOC emissions from pneumatic controllers and supports a natural gas bleed rate 

of zero scfh.

In order to meet an emission limit of zero scfh, natural gas processing plants would likely

need to use an instrument air system. The use of instrument air eliminates natural gas and VOC 

emissions from natural gas-driven pneumatic controllers. We believe that most natural gas 

processing plants already meet the recommended RACT level of control by driving controllers 

with instrument air or other non-gas-driven controls unless there is a specific need for a high 

bleed pneumatic controller. Nonetheless, for those natural gas processing plants that do not have 

an installed instrument air system, the cost of control of installing three representative instrument 

air systems was evaluated under the 2012 NSPS based on the emissions mitigated from the 

number of control loops the system can provide (see section 6.3.1.2 of this chapter). Based on 

this analysis, the cost of this option was considered to be reasonable for natural gas processing 

plants (see Table 6-7 of section 6.3.1.2 of this chapter). The cost of control per ton of VOC

reduced was estimated at $1,700 - $2,800 without savings and $910 - $2,000 with savings. For

determining potential cost impacts, a major assumption made was that processing plants are 

constructed at a location with sufficient electrical service to power the instrument air 

compression system. 

In summary, we recommend the following RACT for each continuous bleed natural gasdriven pneumatic controller located at a natural gas processing plant:
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RACT for Each Continuous Bleed Natural Gas-Driven Pneumatic Controller Located at a 

Natural Gas Processing Plant:

100 Each continuous bleed natural gas driven pneumatic 

controller located at a natural gas processing plant must have a natural gas bleed rate of 

zero scfh (unless there are functional needs, including but not limited to response time, 

safety and positive actuation, requiring a bleed rate greater than zero scfh). 

6.4.2 Continuous Bleed Natural Gas-Driven Pneumatic Controllers Located from 

the Wellhead to the Natural Gas Processing Plant or Point of Custody Transfer to 

an Oil Pipeline

Based on our evaluation of available data obtained in the development of the 2012 NSPS, 

peer review comments received on the “Oil and Natural Gas Sector Pneumatic Devices” white 

paper, and existing regulations that control VOC emissions from pneumatic controllers, we 

recommending a natural gas bleed rate less than or equal to 6 scfh with limited exceptions 

described below as the RACT for controlling VOC emissions from continuous bleed natural gasdriven pneumatic controllers located from the wellhead to the natural gas processing plant or 

point of custody transfer to an oil pipeline.

As indicated in section 6.2.2 of this chapter, low bleed pneumatic controllers can emit up 

to 6 scfh. Both Colorado and Wyoming conditionally require either low- or no-bleed controllers 

(where a high bleed controller is defined as emitting greater than 6 scfh); and the 2012 NSPS 

requires that new and modified individual continuous bleed pneumatic controllers have a bleed 

rate of 6 scfh or less (unless there are functional needs, including but not limited to response 

time, safety and positive actuation, requiring a bleed rate greater than 6 scfh). For purposes of 

this guideline, and consistent with the definition of high bleed controller used for the 2012 NSPS 

and both the Wyoming and Colorado state regulations, a high bleed pneumatic device is defined 

as emitting greater than 6 scfh to the atmosphere. 

Although both Wyoming and Colorado specifically require low bleed or no-bleed 

pneumatic controllers in place of high bleed controllers (where technically and economically

feasible), we are recommending a RACT emission limit of 6 scfh (unless there are functional 

 

100 In the NSPS, we excluded from the NSPS affected facility status non-natural gas-driven pneumatic controllers 

located at natural gas processing plants. Natural gas-driven controllers exempt from the zero VOC emission standard 

under the functional needs exclusion would still be affected facilities and would have certain tagging, recordkeeping 

and reporting requirements.
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needs, including but not limited to response time, safety and positive actuation, requiring a bleed 

rate greater than 6 scfh) apply to each continuous bleed pneumatic controller. This approach 

allows flexibility in how a source chooses to limit VOC emissions from an applicable individual 

pneumatic controller and acknowledges that there may be circumstances where it is not practical 

to meet a 6 scfh limit. By requiring a limit be met, facilities have the option of controlling 

emissions by one or more options presented in section 6.3.1 of this chapter (e.g., replacing a high 

bleed device with a low bleed device and implement enhanced monitoring to mitigate increased 

VOC emissions from poor maintenance/poor operation) depending on site-specific 

circumstances. We are including this flexibility in our recommended RACT to address the varied 

control options and applicability issues (e.g., instrument air systems require access to electrical 

power or a back-up pneumatic controller and access to electric power or back up pneumatic 

controllers may not be available in remote locations) presented in section 6.3.1 of this chapter. 

Although facilities would have flexibility in how they meet the recommended RACT 

level of control, by establishing an emission limit equal to the design bleed rate for a low bleed 

device (6 scfh), we believe that most facilities would likely replace high bleed controllers with 

low bleed controllers (it is assumed about 80 percent of high bleed devices can be replaced with 

low bleed devices).101 For the production segment, we estimated that, on average, 1.41 tons of 

VOC would be reduced annually per device in the production segment from installing a low 

bleed device in place of a high bleed device.

As presented in section 6.3.1.1 of this chapter, the cost of replacing a high bleed device 

with a new low bleed device is on the order of $2,698 per device, and the cost of control in the 

production segment is estimated to be $210 per ton of VOC emissions without savings.

Considering the cost savings of gas recovered from installing a low bleed device in place of a 

high bleed device, it is estimated that there would be an overall net savings. 

In summary, we recommend the following RACT for each single continuous bleed 

natural gas-driven pneumatic controller located from the wellhead to the natural gas processing 

plant or point of custody transfer to an oil pipeline:

 

101 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Options for Reducing

Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas

STAR Program. Washington, DC. October 2006.
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RACT for Each Single Continuous Bleed Natural Gas-Driven Pneumatic Controller

Located from the Wellhead to the Natural Gas Processing Plant or Point of Custody

Transfer to an Oil Pipeline: Each pneumatic controller, which is a single continuous bleed 

natural gas-driven pneumatic controller102 must have a natural gas bleed rate less than or 

equal to 6 scfh (unless there are functional needs, including but not limited to response 

time, safety and positive actuation, requiring a bleed rate greater than 6 scfh).

6.5 Factors to Consider in Developing Pneumatic Controller 

Compliance Procedures

6.5.1 Oil and Natural Gas Production (Individual Continuous Bleed Pneumatic 

Controller with a Natural Gas Bleed Rate Greater than 6 scf Located from 

the Wellhead to the Natural Gas Processing Plant or Point of Custody 

Transfer to an Oil Pipeline)

To ensure that each continuous bleed natural gas-driven pneumatic controller located 

from the wellhead to the natural gas processing plant or point of custody transfer to an oil 

pipeline are operated with a natural gas bleed rate less than or equal to 6 scfh (the recommended 

RACT level of control), we recommend that regulating agencies specify operating, 

recordkeeping and reporting requirements to document compliance. We also recommend that 

regulating agencies require that each pneumatic controller be tagged with the month and year of 

installation and identification information that allows traceability to manufacturer’s 

documentation.

We suggest that regulatory agencies require owners and operators of continuous bleed 

natural gas-driven pneumatic controllers maintain records that (1) document the location and 

manufacturer’s specifications of each pneumatic controller; (2) if applicable, provides a 

demonstration as to why the use of a pneumatic controller with a natural gas bleed rate greater 

than 6 scfh is required (the recommended RACT level of control); and (3) document deviations 

in cases where a pneumatic controller was not operated in compliance with RACT. 

 

102 In the NSPS, we excluded from NSPS affected facility status continuous bleed natural gas-driven pneumatic 

controllers with a bleed rate not greater than 6 scfh (low bleed controllers) located in the production segment. 

Continuous bleed natural gas-driven controllers exempt from the 6 scfh bleed rate emission standard under the 

functional needs exclusion would still be affected facilities and would have certain tagging, recordkeeping and 

reporting requirements. 
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We also recommend that regulatory agencies require owners and operators to submit 

annual reports that includes (1) if applicable, documentation that the use of a pneumatic 

controller with a natural gas bleed rate greater than 6 standard cubic feet per hour is required and 

the reasons why; and (2) the records of deviations that occurred during the reporting period.

The appendix to this document presents example model rule language that incorporates 

compliance elements recommended in this section that states may choose to use in whole or in 

part when implementing RACT.

6.5.2 Natural Gas Processing Segment (Individual Continuous Bleed Natural 

Gas-Driven Pneumatic Controller Located at a Natural Gas Processing 

Plant)

To ensure each continuous bleed natural gas-driven pneumatic controller at natural gas 

processing plants is operated with a natural gas bleed rate of zero (the recommended RACT level 

of control), we suggest that regulatory agencies specify operating, recordkeeping and reporting 

requirements to document compliance. We also suggest that regulatory agencies require that

each pneumatic controller be tagged with the month and year of installation and identification 

information that allows traceability to manufacturer’s documentation.

We recommend that regulatory agencies require owners and operators of pneumatic 

controllers maintain records that (1) document the location and manufacturer’s specifications of 

each pneumatic controller; (2) document that the natural gas bleed rate is zero; and (3) document 

deviations in cases where a pneumatic controller was not operated in compliance with RACT. 

We also recommend that regulatory agencies require owners and operators to submit 

annual reports that include the records of deviations that occurred during the reporting period.

The appendix to this document presents example model rule language that incorporates 

compliance elements recommended in this section that states may choose to use in whole or in 

part when implementing RACT.
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7.0 PNEUMATIC PUMPS

The oil and natural gas industry uses a variety of pneumatic gas-driven pumps where 

there is no reliable electrical power to "control processing problems and protect equipment.”103

Pneumatic pumps are “small positive displacement, reciprocating units used throughout the oil 

and natural gas industry to inject precise amounts of chemicals into process streams or for freeze 

protection glycol circulation.”104 Most chemical injection pumps fall into two main types: (1) 

diaphragm pumps, generally used for heat tracing or (2) plunger/piston, generally used for 

chemical and methanol injection. Pneumatic pumps driven by natural gas emit natural gas, which 

contains VOC. Other types of pneumatic pumps may be driven by gases other than natural gas 

and, therefore, do not emit VOC. The focus of this guideline is natural gas-driven pneumatic 

pumps. This chapter provides a description of pneumatic pumps that are used in the oil and 

natural gas industry, including their function and associated emissions. This chapter also 

provides control techniques used to reduce VOC emissions from pneumatic pumps, along with 

costs and emission reductions. Finally, this chapter provides a discussion of our recommended 

RACT and the associated VOC emission reductions and cost impacts for pneumatic pumps.

7.1 Applicability

For the purposes of this guideline, a pneumatic pump is a positive displacement 

reciprocating unit used for injecting precise amounts of chemicals into a process stream or for 

glycol circulation. The pneumatic pump may use natural gas or another gas to drive the pump. 

The emissions and emissions control discussed herein would apply to natural gas-driven 

chemical/methanol and diaphragm pumps located at natural gas processing plants, and natural 

gas-driven chemical/methanol and diaphragm pumps located from the wellhead to the point of 

custody transfer to the natural gas transmission and storage segment.

 

103 U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 13: Chemical 

Injection Pumps. EPA-600/R-96-080b. June 1996.

104 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Options for Reducing

Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas

STAR Program. Washington, DC. October 2006.
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7.2 Process Description and Emission Sources

7.2.1 Process Description

As noted above, pneumatic pumps are “positive displacement, reciprocating units used 

for injecting precise amounts of chemicals into a process stream or for glycol circulation.”105

Pneumatic pumps often make use of gas pressure where electricity is not readily available.106 In 

the production segment, the supply gas is mostly produced natural gas, whereas in the processing 

segment, the supply gas may be compressed air. For natural gas-driven pneumatic pumps, 

characteristics that affect VOC emissions include the frequency of operation, the size of the unit, 

the supply gas pressure, and the inlet natural gas composition.107

Pneumatic pumps are generally used for one of three purposes: glycol circulation in 

dehydrators, hot oil circulation for heat tracing/freeze protection, or chemical injection. Glycol 

dehydrator pumps may recover energy from the high-pressure rich glycol/gas mixture leaving the 

absorber and use that energy to pump the low-pressure lean glycol back into the absorber.108

Diaphragm pumps are commonly used to circulate hot glycol or other heat-transfer fluids in 

tubing covered with insulation to prevent freezing in pipelines, vessels, and tanks. Chemical 

injection pumps, i.e., piston/plunger pumps or small diaphragm pumps, inject small amounts of 

chemicals such as methanol to prevent hydrate formation or corrosion inhibitors into process 

streams to regulate operations of a plant and protect the equipment. 

Pneumatic pumps have two major components, a driver side and a motive side, which 

operate in the same manner but with different reciprocating mechanisms. Pressurized gas 

provides energy to the driver side of the pump, which operates a piston or flexible diaphragm to 

draw fluid into the pump. The motive side of the pump delivers the energy to the fluid being 

moved in order to discharge the fluid from the pump. The natural gas leaving the exhaust port of 

 

105 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Options for Reducing

Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas

STAR Program. Washington, DC. October 2006.

106 Ibid.

107 Ibid.

108 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Pneumatic Devices. Report for Oil and 

Natural Gas Sector Pneumatic Devices Review Panel. Office of Air Quality Planning and Standards (OAQPS). 

April 2014. Available at http://www.epa.gov/airquality/oilandgas/2014papers/20140415pneumatic.pdf.
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the pump is either directly discharged into the atmosphere or is recovered and used as a fuel gas 

or stripping gas.109

Chemical injection pumps are positive displacement, reciprocating units designed to 

inject precise amounts of chemical into a process stream. Positive displacement pumps work by

allowing a fluid to flow into an enclosed cavity from a low-pressure source, trapping the fluid, 

and then forcing it out into a high-pressure receiver by decreasing the volume of the cavity. A 

complete reciprocating stroke includes two movements, referred to as an upward motion or 

suction stroke, and a downward motion or power stroke. During the suction stroke, the chemical 

is lifted through the suction check valve into the fluid cylinder. The suction check valve is forced 

open by the suction lift produced by the plunger and the head of the liquid being pumped. 

Simultaneously, the discharge check valve remains closed, thus allowing the chemical to remain 

in the fluid chamber. During the power stroke, the plunger assembly is forced downwards, 

immediately shutting off the suction check valve. Simultaneously, the chemical is displaced, 

forcing open the discharge check valve and allowing the fluid to be discharged.110

Typical chemicals injected in an oil or natural gas field are biocides, demulsifiers, 

clarifiers, corrosion inhibitors, scale inhibitors, hydrate inhibitors, paraffin dewaxers, surfactants, 

oxygen scavengers, and H2S scavengers. These chemicals are normally injected at the wellhead 

and into gathering lines or at production separation facilities. Since the injection rates are 

typically small, the pumps are also small. They are often attached to barrels containing the 

chemical being injected.111

Diaphragm pumps are positive displacement pumps, meaning they use contracting and 

expanding cavities to move fluids. Diaphragm pumps work by flexing the diaphragm out of the 

displacement chamber. When the diaphragm moves out, the volume of the pump chamber 

increases and causes the pressure within the chamber to decrease and draw in fluid. The inward 

 

109 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Options for Reducing

Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas

STAR Program. Washington, DC. October 2006.

110 Ibid.

111 Ibid.
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stroke has the opposite effect, decreasing the volume and increasing the pressure of the 

chamber to move out fluid.112

Not all pneumatic pumps are natural gas-driven. At sites without electrical service 

sufficient or reliable enough to power an instrument air compressor control system, mechanical 

or electrically powered pneumatic pumps may be used. Where reliable electrical service is 

available, sources of power other than pressurized natural gas, such as compressed instrument air 

may be used. Because these devices are not natural gas-driven, they do not directly release 

natural gas or VOC emissions. Instrument air systems are feasible only at oil and natural gas 

industry locations where the devices can be driven by compressed instrument air systems and 

have electrical service sufficient and reliable enough to power a compressor. This analysis 

assumes that natural gas processing plants are likely to have electrical service sufficient to power 

an instrument air system, and that most existing gas processing plants use instrument air instead 

of natural gas-driven pumps.

113 The application of electrical controls is discussed further in 

section 7.3 of this chapter.

7.2.2 Emissions Data

7.2.2.1 Summary of Major Studies and Emissions

In the evaluation of the emissions from pneumatic pumps and the potential options 

available to reduce these emissions, numerous studies were consulted. Table 7-1 lists these 

references with an indication of the type of relevant information contained in each reference. In 

addition to these sources, we evaluated the peer reviewer and public comments received on the 

EPA’s white paper, “Oil and Natural Gas Sector Pneumatic Devices.”114

 

112 GlobalSpec. Diaphragm Pumps Information. Available online -

http://www.globalspec.com/learnmore/flow_transfer_control/pumps/diaphragm_pumps.

113 U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic 

Devices. EPA-600/R-96-080k. June 1996.

114 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Pneumatic Devices. Report for Oil and 

Natural Gas Sector Pneumatic Devices Review Panel. Office of Air Quality Planning and Standards (OAQPS). 

April 2014. Available at http://www.epa.gov/airquality/oilandgas/2014papers/20140415pneumatic.pdf
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Table 7-1. Major Studies Reviewed for Consideration of Emissions and Activity Data

Report Name Affiliation Year of 

Report

Activity 

Factors

Emissions 

Data

Control 

Options

Greenhouse Gas Reporting 

Programa EPA 2014 Nationwide X

Inventory of Greenhouse Gas 

Emissions and Sinks: 1990-2012b EPA 2014 Nationwide/Regional X

Methane Emissions from the 

Natural Gas Industryc EPA/GRI 1996 Nationwide X

Methane Emissions from the 

Petroleum Industryd EPA 1999 Nationwide X

Natural Gas STAR Programe EPA 2012 X X

a. U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: 

Climate Change Division. Washington, DC. November 2014.

b U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions from Natural Gas Systems.

Greenhouse Gas Inventory: Emission and Sinks 1990-2012. Washington, DC. And U.S Environmental Protection Agency.

Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 

1990-2012. Washington, DC.

c. U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical Report.

EPA-600/R-96-080b. June 1996; U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry,

Vol. 3: General Methodology. EPA-600/R-96-080c. June 1996.

d. U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 5: Activity Factors.

EPA-600/R-96-080e. June 1996; and U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas

Industry, Vol. 12: Pneumatic Devices. EPA-600/R-96-080k. June 1996.

e. U.S. Environmental Protection Agency. Lessons Learned: Options for Reducing Methane Emissions From Pneumatic Devices in 

the Natural Gas Industry. Office of Air and Radiation: Natural Gas STAR. Washington, DC. October 2006.

7.2.2.2 Representative Pneumatic Pump Emissions

For this analysis, we consulted information in the appendices of Natural Gas STAR 

lessons learned documents on pneumatic pumps,

115,116 the GHGRP, the GHG Inventory, and 

U.S. EPA/GRI Report.

117 The GHGRP and GHG Inventory use emission factors from the U.S. 

EPA/GRI Report. Similarly, we determined that the best available emission factors for 

pneumatic pumps are presented in the U.S. EPA/GRI Report. 

The basic approach used for this analysis was to first approximate methane emissions 

from the average pneumatic pump in the production and processing segments and then estimate 

 

115 U.S. Environmental Protection Agency. Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air.

Office of Air and Radiation: Natural Gas Star. Washington, DC. October 2006.

116 U.S. Environmental Protection Agency. Pro Fact Sheet No. 301. Convert Pneumatics to Mechanical Controls. 

Office of Air and Radiation: Natural Gas Star. Washington, DC. September 2004.

117 Gas Research Institute (GRI)/U.S. Environmental Protection Agency. Research and Development, Methane 

Emissions from the Natural Gas Industry, Volume 13: Chemical Injection Pumps. June 1996 (EPA-600/R -96-

080m).
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VOC and HAP emissions using the gas composition factors from the 2011 Gas Composition 

Memorandum. The specific gas composition ratio used for this analysis were 0.278 lbs VOC per 

pound methane in the production and processing segment. Table 7-2 summarizes the estimated 

average emission factors for a representative pneumatic pump for the production and processing 

segments for both methane and VOC.

Table 7-2. Average Emission Estimates per Pneumatic Device

Segment/Pump 

Type

Emission Factor 

Methane

(scf/day)

a

Emission Factor 

Methane 

(Mcf/yr)b

Emission Factor

Methane 

(tpy)c

Emission Factor

VOC

(tpy)d

Production

Diaphragm 446 163 3.46 0.96

Piston 48.9 18 0.38 0.11

Processing

Small Diaphragm 446 163 3.46 0.96

Medium 

Diaphragm 446 163 3.46 0.96

Large Diaphragm 446 163 3.46 0.96

Small Piston 48.9 18 0.38 0.11

Medium Piston 48.9 18 0.38 0.11

Large Piston 48.9 18 0.38 0.11

a. Data Source: EPA/GRI. Methane Emissions from the Natural Gas Industry, Volume 13: Chemical Injection Pumps. June 1996 

(EPA-600/R -96-080m), Sections 5.1 – Diaphragm Pumps and 5.2 – Piston Pumps.

b. Assumes 365 days/yr operation in natural gas production and processing.

c. Assumes density of methane is 19.26 g/scf. 

d. Assumes 0.278 VOC content per pound of methane.

7.3 Available Controls and Regulatory Approaches

7.3.1 Available VOC Emission Control Options

Natural gas-driven pneumatic pumps emit VOC emissions as part of their normal 

operation. Depending on the type of pump and the constraints of the location, companies can 

utilize a variety of technologies that have been developed over the years. In situations where the 

replacement of natural gas-driven pumps with electric, solar and instrument air pumps is not 

feasible, emissions can be captured via a VRU or routed to a combustion device. 

Sections 7.3.1.1 and 7.3.1.2 discuss the control of VOC emissions by replacing natural 

gas-driven pumps with solar pumps and electric pumps. Section 7.3.1.3 discusses the use of an 

instrument air system to drive the pneumatic pump in order to eliminate VOC emissions. Lastly, 
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section 7.3.1.4 discusses reducing VOC emissions by routing emissions from the pump to a 

combustion device, and section 7.3.1.5 discusses capturing VOC emissions using a VRU. 

7.3.1.1 Solar Pumps

Description

Solar pumps provide the same functionality as natural gas-driven pumps and can be 

utilized at remote sites where electricity is not available. However, peer review comments 

received on the EPA’s white paper “Oil and Natural Gas Sector Pneumatic Devices” noted that 

they predominantly operated solar-powered pneumatic pumps for chemical injection and the 

pumps failed as early as after two to three cloudy days due to insufficient battery charge.118

When solar pumps are properly charged, a solar-charged DC pump can handle a range of 

throughputs up to 100 gallons per day with maximum injection pressure around 3,000 psig and 

have no VOC emissions. Converting natural gas-driven chemical pumps can reduce methane 

emissions by an estimated 3.46 tpy per diaphragm pump and 0.38 tpy per piston pump for all 

segments of the oil and natural gas industry.

119 Based on the gas composition for natural gas in 

the production segment, we estimate that replacement of a pneumatic pump with a solar-powered 

pump will reduce VOC emissions by 0.96 tpy per diaphragm pump and 0.11 tpy for a piston 

pump. 

Control Effectiveness

Replacing a gas-driven pump with a solar pump can result in 100 percent reduction in 

emissions and is feasible in regions where there is sufficient sunlight to power the pump, and 

backup power is not required. Although, as stated above, solar-powered pumps are capable of 

pumping up to 100 gallons per day, they are typically used for low volume applications to inject 

methanol or corrosion inhibitors into a well with typical volumes ranging from 6 to 8 gallons per 

day. In addition to the low volume pumps, large volume pumps used to replace natural gasassisted circulation pumps for glycol dehydrators can also be converted to solar.

 

118 Reese, Carrie, Environmental Compliance Manager. Comments on the Oil and Natural Gas Sector Pneumatic 

Devices. Pioneer Natural Resources.

119 U.S. Environmental Protection Agency. PRO Fact Sheet No. 202. Convert Natural Gas-Driven Chemical Pumps. 

Available online - http://www.epa.gov/gasstar/documents/convertgasdrivenchemicalpumpstoinstrumentair.pdf.
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Cost Impacts

The primary costs associated with conversion to solar pumps are the initial capital 

expenditures. Solar pumps generally have low maintenance costs which are typically lower than 

natural gas-driven pump maintenance costs. The cost being attributed to the replacement of 

pneumatic pumps with solar powered pumps includes the capital cost of the pump and its 

associated operating costs. The operating costs are estimated to be 10 percent of the capital costs. 

Based on the Natural Gas STAR document, “PRO Fact Sheet: Convert Natural Gas-Driven 

Chemical Pumps,”120 the capital (purchase) cost for a solar-powered electric pump is 

approximately $2,000 with solar panels having a lifespan of 15 years and electric motors lasting 

5 years. The total capital costs, including installation and labor is $2,227 (2012 dollars). We 

estimate there would be no additional annual operating costs for solar pumps above and beyond 

that of ordinary field personnel duties. Annualized over the life of the pump at a 7-percent 

discount rate, the annualized costs of replacing a pneumatic pump with a solar pump are $317. In 

addition, the use of solar pumps will have savings realized from the natural gas not released. We 

estimate that each diaphragm pump replaced will save 197 Mcf per year of natural gas from 

being emitted and each piston pump will have a natural gas savings of 22 Mcf per year. The 

value of the natural gas saved based on $4.00 per Mcf would be $786 per year per diaphragm 

pump and $87 per year per piston pump.

7.3.1.2 Electric Pumps

Description

Electric pumps provide the same functionality as natural gas-driven pumps, and are only 

restricted by the use of reliable power. Electric pumps have no VOC emissions, and converting a 

natural gas-driven pneumatic pump to an electric pump can reduce VOC emissions by an 

estimated 0.96 tpy per diaphragm pump and 0.11 tpy per piston pump. 

Control Effectiveness

Replacing a natural gas-driven pump with an electric pump requires the availability of a 

consistent and reliable source of electricity. These pumps are, therefore, more common at 

processing plants or large dehydration facilities that have access to reliable electric power. 

 

120 U.S. Environmental Protection Agency. PRO Fact Sheet No. 202. Convert Natural Gas-Driven Chemical Pumps. 

Available online - http://www.epa.gov/gasstar/documents/convertgasdrivenchemicalpumpstoinstrumentair.pdf.
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Cost Impacts

The primary costs associated with converting natural gas-driven pumps to electric pumps 

are the initial capital expenditures, installation and ongoing operation and maintenance. Based on 

the Natural Gas STAR document, “PRO Fact Sheet: Convert Natural Gas-Driven Chemical 

Pumps”121 the cost of an electric pump to replace a diaphragm pump is $4,647 and to replace a 

piston pump is $1,819 in 2012 dollars depending on the horsepower of the unit.122 The annual 

operating costs for an electric pump are estimated to be $293. Based on these costs annualized 

over the life expectancy of the pump at a 7 percent discount rate, the annualized costs for an 

electric pump to replace a diaphragm pump are $954, and $506 to replace a piston pump. In 

addition, the use of electric pumps will have savings realized from the natural gas not released. 

We estimate that each diaphragm pump replaced will save 197 Mcf per year of natural gas from 

being emitted and each piston pump will have a natural gas savings of 22 Mcf per year. The 

value of the natural gas saved based on $4.00 per Mcf would be $786 per year per diaphragm 

pump and $72 per year per piston pump. 

7.3.1.3 Instrument Air System

Description

Instrument air systems require a compressor, power source, dehydrator, and volume tank. 

The same pneumatic pumps can be used for natural gas and compressed air, without altering any

of the parts of the pneumatic pump, but instrument air eliminates the emissions of natural gas. 

All facilities that have access to an adequate and reliable source of electricity can install an 

instrument air system. The following, taken from the Natural Gas STAR document, “PRO Fact 

Sheet: Convert Gas Pneumatic Controls to Instrument Air,”123 describes the major components 

of an instrument air system:

(1) Compressors used for instrument air delivery are available in various types and sizes, 

from rotary screw (centrifugal) compressors to positive displacement (reciprocating 

piston) types. The size of the compressor depends on the size of the facility, the number 

 

121 Ibid.

122 U.S. Environmental Protection Agency. Lessons Learned. Replacing Gas-Assisted Glycol Pumps with Electric 

Pumps. Available online - http://www.epa.gov/gasstar/documents/ll_glycol_pumps3.pdf. 

123 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Convert Gas 

Pneumatic Controls to Instrument Air. Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. 

2006.
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of control devices operated by the system, and the typical emission rates of these 

devices. The compressor is usually driven by an electric motor that turns on and off, 

depending on the pressure in the volume tank. For reliability, a full spare compressor is 

normally installed. 

(2) A critical component of the instrument air control system is the power source required 

to operate the compressor. Because high-pressure natural gas is abundant and readily 

available, natural gas-driven pneumatic systems can run uninterrupted on a 24-hour, 7-

day per week schedule. The reliability of an instrument air system, however, depends 

on the reliability of the compressor and electric power supply. Most large natural gas 

plants have either an existing electric power supply or have their own power generation 

system. For smaller facilities and remote locations, however, a reliable source of 

electric power can be difficult to assure. In some instances, solar-powered batteryoperated air compressors can be feasible for remote locations, which would both reduce 

VOC emissions and energy consumption. Small natural gas-powered fuel cells are also 

being developed.

(3) Dehydrators, or air dryers, are an integral part of the instrument air compressor system. 

Water vapor present in atmospheric air condenses when the air is pressurized and 

cooled, and can cause a number of problems to these systems, including corrosion of 

the instrument parts and blockage of instrument air piping and controller orifices. 

(4) The volume tank holds enough air to allow the pneumatic control system to have an 

uninterrupted supply of high pressure air without having to run the air compressor 

continuously. The volume tank allows a large withdrawal of compressed air for a short 

time, such as for a motor starter, pneumatic pump, or pneumatic tools, without affecting 

the process control functions. 

Control Effectiveness 

Instrument air eliminates all emissions from natural gas-driven pneumatic pumps, but can 

only be utilized in locations with sufficient and reliable electrical power. Furthermore, 

instrument air systems are more economical and therefore more common at facilities with a high 

concentration of pneumatic devices and where an operator can ensure the system is properly
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functioning.124 Because all emissions can be avoided by converting natural gas-driven chemical 

pumps to instrument air, methane emissions can be reduced by an estimated 3.46 tpy per 

diaphragm pump and 0.38 tpy per piston pump. Based on the gas composition for natural gas in 

the production segment, we estimate that replacement of a pneumatic pump converted to 

instrument air will reduce VOC emissions by 0.96 tpy per diaphragm pump and 0.11 tpy for a 

piston pump. 

Cost Impacts

As stated previously, instrument air conversions require a compressor with a capacity 

based on the number of control loops at the location. The compressor size is equivalent to the 

volume of gas used by the control loops after adjusting for gas losses during drying, plus any

utility air necessary at the facility. This volume can either be calculated via a meter or utilizing a 

rule of thumb of one cubic foot per minute (cfm) of instrument air per control loop.125

The costs associated with instrument air systems are primarily capital costs for the 

compressor(s), air dryer and the volume tank, but also include operational costs for electricity to 

drive the compressor motor. Other components of the instrument air system including piping, 

control instruments and valve actuators would already be in place for a gas system. We assume 

that existing processing plants have an instrument air system in place, including backup systems, 

and that the cost of increasing air load on the system would be confined to the incremental cost 

associated with upgrading or replacing the compressor and connecting the pumps to the system. 

The size of the compressor required would depend on the additional air load required for the 

instrument air system to handle the pneumatic pumps. Table 7-3 summarizes cost estimates to 

replace various size compressors in an existing instrument air system.

 

124 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Convert Gas 

Pneumatic Controls to Instrument Air. Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. 

2006.

125 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Options for 

Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: 

Natural Gas STAR Program. Washington, DC. October 2006.
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Table 7-3. Cost of Compressor Replacement for Existing Instrument Air System

Type of Pump Size 

Option

Total Capital Costs

($2012)

Annualized

Cost

Total O&M 

($2012)

Annualized with 

Operating Costs

Diaphragm Small $5,999 $854 $9,197 $10,051

Diaphragm Medium $29,989 $4,270 $28,002 $32,271

Diaphragm Large $52,779 $7,515 $64,880 $72,394

Piston Small $5,999 $854 $9,197 $10,051

Piston Medium $29,989 $4,270 $28,002 $32,271

Piston Large $52,779 $7,515 $64,880 $72,394

7.3.1.4 Route Emissions to an Existing or New Combustion Device

Description

Combustion devices can generally reduce 95 percent of the emissions routed to it. 

Combustion requires a reliable ignition source where the average gas consumption per pilot 

burner is 70 scf per hour.126 Typical combustion devices used in the oil and natural gas industry

to control VOC emissions are discussed in greater detail in section 4.3.1.2 of chapter 4 of this 

document. It is assumed that most processing plants and large dehydration facilities have at least 

one existing combustion device on-site.

 

126 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Options for 

Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: 

Natural Gas STAR Program. Washington, DC. October 2006.
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Control Effectiveness

Routing emissions from a natural gas-driven pump to an existing combustion device, or a 

newly installed combustion device does not reduce the volume of natural gas discharged from 

the pump, but rather combusts the gas. Based on the gas composition for natural gas in the 

production segment, we estimated that routing emissions to a combustion device would reduce 

VOC emissions by an estimated 0.91 tpy per diaphragm pump and 0.1 tpy for a piston pump. 
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Cost Impacts

Routing natural gas to an existing combustion device or installing a new combustion 

device have associated capital costs and operating costs. Based on costs for a combustion device 

provided in the 2011 NSPS TSD, the capital costs for installing a new combustion device to 

control emissions are estimated to cost $32,301 in 2008 dollars.127 Escalating these costs to 2012 

dollars, the estimated capital costs for installing a new combustion device are $34,250 and the 

annual operating costs are $17,001. Based on the life expectancy for a combustion device, we

estimate the annualized costs of installing a new combustion device to be approximately

$21,877, and the annualized costs of routing emissions to an existing combustion device to be 

$285, using a 7 percent discount rate. Because the natural gas captured is combusted there is no 

gas savings associated with the use of a combustion device to reduce VOC emissions. Table 7-4 

presents the estimated VOC cost of control for emission reductions from routing natural gasdriven pump emissions to an existing combustion device, and Table 7-5 presents the cost of 

control for routing natural gas-driven pump emissions to a new combustion device.

Table 7-4. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to an 

Existing Combustion Device

Pump Type/

Segment

VOC Emission 

Reductions

(tpy/pump)

Annualized Costs

($2012)

VOC Cost of 

Control ($2012/ton)

Diaphragm Pumps

Production 0.91 $285 $312

Processing 0.91 $285 $312

Piston Pumps

Production 0.10 $285 $2,840

Processing 0.10 $285 $2,840

 

127 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil 

and Natural Gas Production, Transmission, and Distribution – Background Technical Support Document for 

Proposed Standards. July 2011. EPA Document Number EPA-453/R-11-002.
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Table 7-5. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to a New 

Combustion Device

Pump Type/ 

Segment

VOC Emission 

Reductions

(tpy/pump)

Annualized Costs

($2012)

VOC Cost of Control 

($2012/ton)

Diaphragm Pumps

Production 0.91 $21,877 $23,944

Processing 0.91 $21,877 $23,944

Piston Pumps

Production 0.10 $21,877 $218,017

Processing 0.10 $21,877 $218,017

7.3.1.5 Route Emissions to a Vapor Recovery Unit (VRU)

Description

Vapor recover units capture low pressure vapor streams, increase the pressure by means 

of a compressor, and then route the vapor stream to a process or other useful purpose. These 

systems typically include a backup compressor system to allow for shutdowns and repairs. Vapor 

recovery units are more economical for facilities with multiple natural gas emission sources that 

can be routed to the VRU. Some of these other emission sources can include tanks, dehydrators, 

and compressors and as a result, VRUs are more common at natural gas processing plants. Vapor 

recovery units are discussed in greater detail in section 4.3.1.1 of chapter 4 of this document.

Control Effectiveness

Use of a vapor recovery technology has the potential to reduce the emissions from natural 

gas-driven pumps by 100 percent if all vapor is recovered. However, the effectiveness of the 

natural gas capture system (typically less than 100 percent) and downtime of the VRU for repairs 

and maintenance would reduce the overall emission reductions and therefore, we estimate that 

routing emissions from a natural gas-driven pump to an existing or newly installed VRU can 

reduce the natural gas emitted by approximately 95 percent, while at the same time, capturing the 

natural gas for beneficial use. We estimate that methane emission reductions for routing gas to a 

VRU to be 3.29 tpy for a diaphragm pump and 0.36 tpy for a piston pump. Based on the gas 

composition for natural gas in the production segment, we estimate that routing emissions to a 

VRU will reduce VOC emissions by 0.91 tpy per diaphragm pump and 0.1 tpy for a piston 

pump. 
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Cost Impacts

Based on costs for a VRU provided in the 2011 NSPS TSD for pneumatic pumps, the 

capital costs and installation costs for a VRU was estimated to be $98,186 in 2008 dollars. 128 We 

estimate the capital costs of installing a VRU to be $104,111 and the annual operation and 

maintenance cost to be $9,932 in 2012 dollars. The total annualized costs of a new VRU are

estimated to be $24,755 based on a 7 percent discount rate.

If a VRU is already on-site, then the additional costs for routing emissions from a pump 

are small, as the majority of costs are piping. We estimated the cost of routing emissions to an 

existing VRU to be $2,000 in 2012 dollars. The annualized costs of routing natural gas emissions 

to an existing VRU are estimated to be $285 based on a 7 percent discount rate. In addition, there 

is potential for beneficial use of natural gas recovered through the VRU. We estimated the 

annual natural gas recovered to be 187 Mcf per year per diaphragm pump and 21 Mcf per year 

per piston pump. The resulting natural gas savings is estimated to be $749 per diaphragm pump 

and $84 per piston pump, per year based on a value of $4.00 per Mcf of natural gas recovered. 

Table 7-6 presents the estimated VOC cost of control for routing natural gas-driven pump 

emissions to an existing VRU, and Table 7-7 presents the estimated VOC cost of control for 

routing gas-driven pump emissions to a new VRU.

Table 7-6. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to an 

Existing VRU

Pump Type/

Segment

VOC Emission 

Reductions

(tpy/pump)

Annualized Costs

($2012)

VOC Cost of Control ($2012/ton)

Without savings With savings

Diaphragm Pumps

Production 0.91 $285 $312 ($507)

Processing 0.91 $285 $312 ($507)

Piston Pumps

Production 0.10 $285 $2,840 $2,007

Processing 0.10 $285 $2,840 $2,007

 

128 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil 

and Natural Gas Production, Transmission, and Distribution – Background Technical Support Document for 

Proposed Standards. July 2011. EPA Document Number EPA-453/R-11-002.
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Table 7-7. VOC Cost of Control for Routing Natural Gas-Driven Pump Emissions to a New 

VRU

Pump Type/

Segment

VOC Emission 

Reductions

(tpy/pump)

Annualized Costs

($2012)

VOC Cost of Control ($2012/ton)

Without savings With savings

Diaphragm Pumps

Production 0.91 $24,755 $27,094 $26,274

Processing 0.91 $24,755 $27,094 $26,274

Piston Pumps

Production 0.10 $24,755 $246,697 $245,860

Processing 0.10 $24,755 $246,697 $245,860

7.3.2 Existing Federal, State and Local Regulations

7.3.2.1 Federal Regulations that Specifically Require Control of VOC 

Emissions

The EPA has proposed federal requirements for natural gas-driven pneumatic pumps 

under 40 CFR part 60, subpart OOOOa (subpart OOOOa). Under the proposed subpart OOOOa, 

each natural gas-driven chemical/methanol and diaphragm pump located at a natural gas 

processing plant must have zero natural gas emissions, and each natural gas-driven 

chemical/methanol and diaphragm pump located outside of a natural gas processing plant must 

reduce VOC emissions by 95 percent or greater when there is a control device already in place at 

the facility, or when a control device is installed at an existing facility. 

7.3.2.2 State and Local Regulations that Specifically Require Control of VOC 

Emissions

States may have permitting restrictions on VOC emissions that may apply to an 

emissions source as a result of an operating, NSR NA, or PSD permit (e.g., on a case-by-case 

basis) based on air quality maintenance or improvement goals of an area. Permits specify what 

construction is allowed, what emission limits must be met, and often how the source may be 

operated. To assure that sources follow the permit requirements, permits also contain monitoring, 

recordkeeping, and reporting requirements. Permits specify what construction is allowed, what 

emission limits must be met, and often how the source must be operated. To assure that sources 
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Pneumatic Pumps

follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting 

requirements. 

At least one state (Wyoming) requires emissions associated with the discharge streams 

from all natural gas-operated pneumatic pumps be controlled by at least 98 percent or routed into 

a closed loop system (e.g., sales line, collection line, fuel supply line). Several states also have 

registration rules for controlling fugitive VOC emissions (which may include fugitive emissions 

from pneumatic pumps).

7.4 Recommended RACT Level of Control

Based on our evaluation of available data obtained in the development of the 2015 NSPS 

proposal and peer review comments received on the EPA’s white paper “Oil and Natural Gas 

Sector Pneumatic Devices,” and considering that Wyoming already requires emissions 

associated with the discharge streams from all natural gas-operated pneumatic pumps to be 

controlled by at least 98 percent or routed into a closed loop system (e.g., sales line, collection 

line, fuel supply line), we recommend that VOC emissions from individual natural gas-driven 

piston and diaphragm pumps located from the wellhead to the point of custody transfer to the 

natural gas transmission and storage segment and at a natural gas processing plant be controlled 

by RACT.

Our recommended RACT for existing individual gas-driven piston and diaphragm pumps 

located from the wellhead to the point of custody transfer to the transmission and storage 

segment, using natural gas emissions as a surrogate for VOC emissions, is to reduce natural gas 

emissions by 95 percent by routing emissions to a control device where there is an existing 

control device available on-site. If there is an existing VRU available on-site, then we 

recommend RACT to be reducing natural gas emissions by 95 percent by using the VRU to route 

emissions to a process. If a control device is subsequently installed at the facility where the pump 

is located, then the owner or operator would have to route the natural gas emission stream from 

the pump to the newly installed control device. Our rationale for selecting 95 percent control 

when there is an existing control device is that, as presented in Table 7-4 in section 7.3.1.4 of this 

chapter, the VOC cost of control when an existing combustion device is available on-site was 

estimated to be $312/ton for diaphragm pumps and $2,850/ton for piston pumps. As presented in 

Table 7-6 in section 7.3.1.5 of this chapter, the VOC cost of control when an existing VRU is 

available on-site was estimated to be a cost savings for diaphragm pumps and $2,007/ton for 
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piston pumps. We consider these costs to be reasonable. Requiring control where there is not an 

existing control device on-site was not considered to be reasonable available technology, and the 

costs per ton of VOC reduced are estimated at greater than $20,000 per ton of VOC reduced for 

diaphragm pumps and over $200,000 per ton of VOC reduced for piston pumps.

Our recommended RACT for existing individual chemical/methanol and diaphragm 

pump located at natural gas processing plants is that they have zero natural gas emissions (unless 

there are functional needs, including but not limited to response time, safety and positive 

actuation, requiring an emission rate greater than zero). Our rationale for selecting a natural gas 

emission rate of zero (with functional and safety exceptions) for our recommended RACT is 

based on the ability of most natural gas processing plants to install and utilize an instrument air 

system. As discussed in section 7.3.1.3 of this chapter, by using an instrument air system, 

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

the parts of the pneumatic system. Therefore, the use of instrument air eliminates natural gas and 

VOC emissions from each gas-driven pneumatic pump and supports a natural gas emission rate 

of zero.

In summary, we recommend the following RACT for pneumatic pumps in the oil and 

natural gas industry:

(1) Each Natural Gas-Driven Chemical/Methanol and Diaphragm Pump Located at a Natural 

Gas Processing Plant: Each pump must have zero natural gas emissions. 

(2) Each Natural Gas-Driven Chemical/Methanol and Diaphragm Pump Located From the 

Wellhead to the Natural Gas Processing Plant: If there is a control device located on-site 

of the location of the pump, using natural gas as a surrogate for VOC, each pump must 

reduce natural gas emissions by 95 percent by routing to the control device or to a 

process. If there is no existing control device at the location of the pneumatic pump, 

submit a certification that there is no device. If a control device is subsequently added to 

the site where the pump is located, then the natural gas emissions from the pump must be 

routed to the newly installed control device.

Although sources have a choice on how they meet the RACT level of control, the 

technologies that will likely be used to meet the RACT level of control for each natural gasdriven pneumatic pump located from the wellhead to the natural gas processing plant are either 

routing the natural gas emissions to an on-site existing combustion device (or a subsequently
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installed combustion device) or routing the natural gas emissions to a process using an on-site 

existing VRU (or a subsequently installed VRU). 

Similarly, the technology that will likely be used to meet the RACT level of control for 

each natural gas-driven chemical/methanol and diaphragm pump located at a natural gas 

processing plant is the use of an existing instrument air system assumed to already exist on-site 

at natural gas processing plants.

7.5 Factors to Consider in Developing Pneumatic Pump Compliance 

Procedures

7.5.1 Oil and Natural Gas Production Segment Recommendations

We recommend that regulatory agencies require each pneumatic pump be tagged with the 

date that the pneumatic pump is required to comply with the rule (as established by the 

regulating agency) that allows traceability. We also suggest that regulatory agencies require 

owners and operators of pneumatic pumps to maintain records that document the location and 

manufacturer’s specifications of each pneumatic pump that are tied to the identification 

information of each pump. We also recommend that regulatory agencies require owner or 

operators to document deviations in cases where a pneumatic pump was not operated in 

compliance with RACT. Lastly, we suggest that regulatory agencies require owners and 

operators to submit annual reports that include the records of deviations that occurred during the

reporting period.

The appendix to this document presents example model rule language that incorporates 

compliance elements recommended in this section that states may choose to use in whole or in 

part when implementing RACT.

7.5.2 Natural Gas Processing Segment Recommendations

We suggest that regulatory agencies require each pneumatic pump be tagged with the 

date that the pneumatic pump is required to comply with the rule (as established by the 

regulating agency) that allows traceability. We also recommend that regulatory agencies require 

owners and operators of pneumatic pumps to maintain records that document the location and 

manufacturer’s specifications of each pneumatic controller that are tied to the identification 

information of each pump. The owner or operator should also be required to document 

deviations in cases where a pneumatic pump was not operated in compliance with RACT. Lastly, 
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we recommend that regulatory agencies require owners and operators to submit annual reports 

that include the records of deviations that occurred during the reporting period.

The appendix to this document presents example model rule language that incorporates 

compliance elements recommended in this section that states may choose to use in whole or in 

part when implementing RACT.
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8-1

Equipment Leaks

8.0 EQUIPMENT LEAKS FROM NATURAL GAS PROCESSING 

PLANTS

This chapter presents the causes for equipment leaks from natural gas processing plants, 

and provides emission estimates for “model” facilities in the processing segment of the oil and 

natural gas industry. Methods that are designed to reduce equipment leak emissions are 

presented, along with our recommended RACT and the associated VOC emission reductions and 

cost impacts for equipment component leaks from natural gas processing plants.

8.1 Applicability

For purposes of this guideline, the emissions and emission controls discussed herein 

would apply to the group of all equipment (except compressors) within a process unit located at a

natural gas processing plant in VOC service or in wet gas service. For a piece of equipment to be 

considered not in VOC service, it must be determined that the VOC content can be reasonably

expected never to exceed 10.0 percent by weight at or greater than 300 hours per year. For a 

piece of equipment to be considered in wet gas service, the piece of equipment must contain or 

contact the field gas before the extraction step at a natural gas processing plant. Equipment is 

defined as each pump, pressure relief device, open-ended valve or line, valve, and flange or other 

connector that is in VOC service or in wet gas service

8.2 Process Description and Emission Sources

8.2.1 Process Description

Natural gas processing involves the removal of natural gas liquids from field gas, 

fractionation of mixed natural gas liquids to natural gas products, or both. The types of process 

equipment used to separate the liquids are separators, glycol dehydrators, and amine treaters. In 

addition, centrifugal and/or reciprocating compressors are used to pressurize and move the 

natural gas from the processing facility to the transmission stations.

There are several potential sources of equipment leak emissions at natural gas processing 

plants. Equipment such as pumps, pressure relief devices, valves, flanges, and other connectors 

are potential sources that can leak due to seal failure. Other sources, such as open-ended lines 

and valves may leak for reasons other than faulty seals. In addition, corrosion of welded 

connections, flanges, and valves may also be a cause of equipment leak emissions. The following 
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8-2

Equipment Leaks

sub-sections describe potential equipment leak sources and the magnitude of the VOC emissions 

from natural gas processing plants. 

Due to the large number of valves, pumps, and other equipment within natural gas 

processing plants, VOC emissions from leaking equipment can be significant (chapter 2.2 of the 

1983 CTG129 presents a description of these equipment components and is not repeated here). 

8.2.2 Equipment Leak Emission Data and Emission Factors

8.2.2.1 Summary of Major Studies and Emission Factors

The 2012 NSPS STSD evaluated emissions data from equipment leaks collected from 

chemical manufacturing and petroleum production to assist in the development of control 

strategies for reducing VOC emissions from these sources.130,131,132 Table 8-1 presents a list of 

the studies consulted along with an indication of the type of information contained in the study. 

In addition to these sources, we evaluated the peer reviewer and public comments received on 

the EPA’s white paper, “Oil and Natural Gas Sector Leaks.”133

Table 8-1. Major Studies Reviewed for Consideration of Emissions and Activity Data

Report Name Affiliation Year of 

Report

Activity

Factors

Emissions 

Data

Control 

Options

Protocol for Equipment Leak 

Emission Estimatesa

EPA 1995 None X X

Methane Emissions from the 

Natural Gas Industry: 

Equipment Leaksb

EPA/GRI 1996 Nationwide X X

Greenhouse Gas Reporting 

Programc

EPA 2014 Nationwide X X

 

129 U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, 

NC, 27711. Guideline Series. Control of Volatile Organic Compound Equipment Leaks from Natural Gas/Gasoline 

Processing Plants. December 1983. EPA-450/3-83-007

130Memorandum from David Randall, RTI and Karen Schaffner, RTI to Randy McDonald, U.S. Environmental 

Protection Agency. Control Options and Impacts for Equipment Leaks: Chemical Manufacturing Area Source 

Standards. September 2, 2008.

131Memorandum from Kristen Parrish, RTI and David Randall, RTI to Karen Rackley, U.S. Environmental 

Protection Agency. Final Impacts for Regulatory Options for Equipment Leaks of VOC on SOCMI. October 30, 

2007.

132Memorandum from Kristen Parrish, RTI, David Randall, RTI, and Jeff Coburn, RTI to Karen Rackley, U.S. 

Environmental Protection Agency. Final Impacts for Regulatory Options for Equipment Leaks of VOC in Petroleum 

Refineries. October 30, 2007.

133 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Leaks. Report for Oil and Natural Gas 

Sector Leaks Review Panel. Office of Air Quality Planning and Standards (OAQPS). April 2014.
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Equipment Leaks

Report Name Affiliation Year of 

Report

Activity

Factors

Emissions 

Data

Control 

Options

Inventory of Greenhouse Gas 

Emissions and Sinks: 1990-

2012d

EPA 2014 Nationwide X

Methane Emissions from the 

Natural Gas Industrye,f,g,h EPA/GRI 1996 Nationwide X X

Methane Emissions from the 

U.S. Petroleum Industryi EPA 1996 Nationwide X

Methane Emissions from the 

US Petroleum Industryj EPA 1999 Nationwide X

Oil and Gas Emission 

Inventories for Western 

Statesk

Western 

Regional Air 

Partnership

2005 Regional X X

Recommendations for 

Improvements to the Central 

States Regional Air 

Partnership's Oil and Gas 

Emission Inventoriesl

Central States 

Regional Air 

Partnership

2008 Regional X X

Oil and Gas Producing 

Industry in Your Statem

Independent 

Petroleum 

Association of 

America

2009 Nationwide

Emissions from Natural Gas 

Production in the Barnett 

Shale and Opportunities for 

Cost-effective 

Improvementsn

Environmental 

Defense Fund 2009 Regional X X

Emissions from oil and 

Natural Gas Production 

Facilitieso

Texas 

Commission 

for 

Environmental 

Quality

2007 Regional X X

Petroleum and Natural Gas 

Statistical Datap

U.S. Energy 

Information 

Administration

2007-

2009 Nationwide

Preferred and Alternative 

Methods for Estimating Air 

Emissions from Oil and Gas 

Field Production and 

Processing Operationsq

EPA 1999 X X

a. U.S. Environmental Protection Agency, Protocol for Equipment Leak Emission Estimates. Office of Air Quality Planning and 

Standards. Research Triangle Park, NC. November 1995. EPA-453/R-95-017. Available at 

http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf.

b. Gas Research Institute (GRI)/U.S. Environmental Protection Agency. Research and Development, Methane Emissions from 

the Natural Gas Industry, Volume 8: Equipment Leaks. June 1996 (EPA-600/R-96-080h).

c. U.S. Environmental Protection Agency. 

Greenhouse Gas Reporting Program. (Annual Reporting; Current Data Available for 2011-2013). 2014.
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Equipment Leaks

d. U.S. Environmental Protection Agency (EPA). Inventory of Greenhouse Gas Emissions and Sinks: 1990-2012. Climate 

Change Division, Washington, DC.

e. U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical Report. 

EPA-600/R-96-080b.June 1996.

f. U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 3: General Methodology. 

EPA-600/R-96-080c.June 1996.

g. U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 5: Activity Factors. 

EPA-600/R-96-080e.June 1996.

h. U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Vol. 6: Vented and 

Combustion Source Summary Emissions. EPA-600/R-96-080f. June 1996.

i. U.S. Environmental Protection Agency/GRI. Methane Emissions from the U.S. Petroleum Industry, Draft Report. June 14, 

1996.

j. ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry. Prepared for the U.S. Environmental Protection 

Agency. 1999.

k. ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States. Prepared for Western 

Governors’ Association. December 27, 2005. 

l. ENVIRON International Corporation. Recommendations for Improvements to the Central States Regional Air Partnership's 

Oil and Gas Emission Inventories Prepared for Central States Regional Air Partnership. November 2008.

m. Independent Petroleum Association of America. Oil and Gas Producing Industry in Your State.

n. Armendariz, Al. Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost-Effective 

Improvements. Prepared for Environmental Defense Fund. January 2009. 

o. Eastern Research Group, Inc. Emissions from Oil and Gas Production Facilities. Prepared for the Texas Commission on 

Environmental Quality. August 31, 2007.

p. U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price. Energy Information Administration. 

Natural Gas Navigator. Retrieved online on 12 Dec 2010 at http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm.

q Eastern Research Group, Inc. Preferred and Alternative Methods for Estimating Air Emissions from Oil and Gas Field 

Production and Processing Operation. Prepared for the U.S. Environmental Protection Agency. September 1999.

8.2.2.2 Natural Gas Processing Model Plant

Natural gas processing plants can consist of a variety of combinations of process 

equipment and components. In order to conduct analyses to be used in evaluating potential 

options to reduce emissions from leaking equipment, the 2011 NSPS TSD and the 2012 NSPS 

STSD used a model plant approach. 

Information related to equipment counts were obtained from a natural gas industry

report.134 This document provided average equipment counts for gas production and gas 

processing segments. These average counts were used to develop a model plant. These 

equipment counts are consistent with those contained in the EPA’s analysis to estimate methane 

emissions conducted in support of the GHGRP. The natural gas processing model plant is 

discussed in the following section. A summary of the model plant production equipment counts 

for a gas processing facility is provided in Table 8-2.

 

134 U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks.

Table 4-13, June 1996. (EPA-600/R-96-080h)
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Table 8-2. Equipment Counts for Natural Gas Processing Model Plant

Equipment

Equipment Count

(non-compressor 

equipment)

Valves 1,392

Connectors 4,392

Open-Ended Lines 

(OEL) 134

Pressure Relief Valve 

(PRV) 29

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

Equipment Leaks, Table 4-13, June 1996. (EPA-600/R-96-080h)

8.2.2.3 Natural Gas Processing Model Plant Emissions

Overview of Approach

The EPA gathered equipment leak data and cost information for the development of the 

proposed Uniform Standards for Equipment Leaks rule. These Uniform Standards data were used 

to estimate baseline emissions for a natural gas processing model plant for the 2012 NSPS STSD 

and provide the baseline and controlled emission options for processing plants presented in this 

guideline.

135,136

The baseline emissions were defined as being equivalent to a 40 CFR part 60, subpart VV

(subpart VV) leak detection and repair (LDAR) program, which represents the same set of

requirements that apply to natural gas processing plants under 40 CFR part 60, subpart KKK 

(subpart KKK). The 2012 NSPS requires the implementation of 40 CFR part 60, subpart VVa 

(subpart VVa) and currently applies to natural gas processing plants constructed or modified 

after August 23, 2011. It is assumed that natural gas processing plants constructed or modified 

on or before August 23, 2011 currently still comply with subpart KKK, which is similar to the 

control level of subpart VV. We evaluated requiring a similar subpart VVa level of control to 

these plants as was required under the 2012 NSPS. We used leak frequency data (refers to the

 

135 Memorandum from Cindy Hancy, RTI International to Jodi Howard, EPA/OAQPS. Analysis of Emission

Reduction Techniques for Equipment Leaks. December 21, 2011.

136 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil 

and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support 

Document for the Final New Source Performance Standards. April 2012. EPA Docket Number EPA-HQ-OAR2010-0505-4550.
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Equipment Leaks

estimated percentage of equipment that will be found leaking at a given leak definition) to

calculate emission estimates, in addition to several other sources of information (including the

Protocol for Equipment Leak Emissions Estimates and industry data).

137 Table 8-3 provides a 

summary of the equipment leak frequency data used for the natural gas processing model plant. 

Emission factors are the estimated leak rates for an equipment type at a given leak definition and

are normally given in kg/hr/piece of equipment. Table 8-4 provides a summary of the VOC 

equipment leak emission factors representing the subpart VVa level of control was used for the 

natural gas processing model plant. 

Table 8-3. Summary of Equipment Leak Frequency for Natural Gas

LDAR Program

a Valves

(percent)

Connectors

(percent) Baseline 1.18/1.18 NA

Valves 5.95/1.91 NA

Connectors NA 1.70/0.81

NA = Not Applicable; no equipment leak frequency percent data were available.

Data Source: Memorandum from Cindy Hancy, RTI International to Jodi Howard, EPA/OAQPS, Analysis of

Emission Reduction Techniques for Equipment Leaks, December 21, 2011, Table 5.

a. The leak frequencies provided in the tables are presented as initial leak frequency and subsequent leak

frequency under the subpart VVa level of control.

Table 8-4. Summary of VOC Equipment Leak Emission Factors for the Natural Gas 

Processing Model Plant

Component Uncontrolled 

(kg/comp-hr)

Baseline 

(kg/comp-hr)a

Subpart VVa

Control Level

(kg/comp-hr)b

Valves 3.71E-04 2.24E-04 8.85E-05

Connectors 1.04E-04 1.04E-04 3.95E-05

OEL 2.30E-03 7.34E-05 NA

PRV 1.60E-01 9.80E-02 NA

NA = Not Applicable 

Data Source: Memorandum from Cindy Hancy, RTI International to Jodi Howard, EPA/OAQPS, Analysis of Emission

Reduction Techniques for Equipment Leaks, December 21, 2011, Table 7.

a. The baseline option is assumed to be equivalent to a subpart VV LDAR program.

b. Assumed to be equivalent to a subpart VVa LDAR program.

 

137 U.S. Environmental Protection Agency. Protocol for Equipment Leak Emission Estimates. November 1995.

EPA-453/R-95-017
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Equipment Leaks

8.3 Available Controls and Regulatory Approaches 

8.3.1 Available VOC Emission Control Options

The EPA has determined that leaking equipment, such as valves, pumps and connectors, 

are a significant source of VOC emissions from natural gas processing plants. The following 

subsections describe the techniques used to reduce emissions from these sources.

8.3.1.1 Leak Detection and Repair Program

The most commonly employed control technique for equipment leaks is the 

implementation of a LDAR program. Emission reductions from implementing a LDAR program 

can potentially reduce product losses, increase safety for workers and operators, decrease 

exposure of hazardous chemicals to the surrounding community, and reduce emissions fees. The 

elements of an effective LDAR program include:

(1) Identifying Equipment;

(2) Leak Definition;

(3) Monitoring Equipment;

(4) Repairing Equipment; and

(5) Recordkeeping.

The primary sources of equipment leak emissions from natural gas processing plants are 

valves and connectors, because these are the most prevalent equipment and can number in the 

thousands (see Table 8-2). The major cause of emissions from valves and connectors is a seal or 

gasket failure due to normal wear or improper maintenance. A leak is detected whenever the 

measured concentration exceeds the threshold standard (i.e., leak definition) for the applicable 

regulation. Leak definitions vary by regulation, equipment type, service (e.g., light liquid, heavy

liquid, gas/vapor), and monitoring interval. Most NSPS regulations have a leak definition of 

10,000 ppm, while many National Emission Standards for Hazardous Air Pollutants (NESHAP)

regulations use a 500-ppm or 1,000-ppm leak definition. In addition, some regulations define a 

leak based on visual inspections and observations (such as fluids dripping, spraying, misting or 

clouding from or around equipment), sound (such as hissing), and smell.

For many NSPS and NESHAP regulations with leak detection provisions, the primary

method for monitoring to detect leaking components is EPA Reference Method 21 (40 CFR part 
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Equipment Leaks

60, appendix A-7). Method 21 is a procedure used to detect VOC leaks from equipment using a 

toxic vapor analyzer (TVA) or organic vapor analyzer (OVA). 

A second method for monitoring to detect leaking components is optical gas imaging 

(OGI) using an infrared camera. The infrared camera may be passive or active. The passive 

infrared cameras scan an area to produce images of equipment leaks from a number of sources. 

Active infrared cameras point or aim an infrared beam at a potential source to indicate the 

presence of equipment leaks. The optical imaging camera can be very efficient in monitoring 

multiple pieces of equipment in a short amount of time. However, the optical imaging camera 

cannot quantify the amount or concentration of the equipment leak. 

Acoustic leak detectors measure the decibel readings of high frequency vibrations from 

the noise of leaking fluids from equipment leaks using a stethoscope-type device. The decibel 

reading, along with the type of fluid, density, system pressure, and component type can be 

correlated into leak rate by using algorithms developed by the instrument manufacturer. The 

acoustic detector does not decrease the monitoring time because components are measured 

separately, like the OVA or TVA monitoring. The accuracy of the measurements using the 

acoustic detector can also be questioned due to the number of variables used to determine the 

equipment leak emissions.

In addition, other monitoring tools such as soap solution and electronic screening devices 

can be used to monitor process components. Other factors that can improve the efficiency of a 

LDAR program include training programs for equipment monitoring personnel and tracking 

systems that address the cost efficiency of alternative equipment (e.g., competing brands of 

valves in a specific application).

Subpart VVa LDAR Program

One LDAR option to control VOC emissions from natural gas processing plant 

equipment leaks is the implementation of the subpart VVa LDAR program. This program is 

similar to the subpart VV monitoring program (whose requirements are cross-referenced in 

subpart KKK), but finds more leaks due to the lower leak definition, increased monitoring 

frequency and the addition of connectors to the components being monitored, thereby achieving 

better emission reductions. 
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Description

The subpart VVa LDAR program requires the monitoring of pumps, compressors, 

pressure relief devices, sampling connection systems, open-ended lines, valves and connectors. 

These components are monitored with an OVA or TVA to determine if a component is leaking 

and measure the concentration of the organics if the component is leaking. Connectors, valves, 

and pressure relief devices have a leak definition of 500 ppmv. Valves are monitored monthly, 

connectors are monitored annually, and open-ended lines and pressure relief valves have no 

monitoring requirements, but are required to operate without any detectable emissions. 

Compressors are not included in this leak detection and repair option and are regulated 

separately.

Control Effectiveness

The control effectiveness of an LDAR program is based on the frequency of monitoring, 

leak definition, frequency of leaks, percentage of leaks that are repaired, and the percentage of 

reoccurring leaks. The control effectiveness of a leak program can vary from 45 to 96 percent 

and is dependent on the frequency of monitoring and the leak definition.138 Descriptions of the 

frequency of monitoring and leak definition are described further below.

Monitoring Frequency. The monitoring frequency is the number of times each piece of 

equipment is checked for leaks over a given period of time. With more frequent monitoring,

leaks are found and repaired sooner thus providing higher control effectiveness. 

Leak Definition. The leak definition describes the local VOC concentration at the surface 

of an equipment source where indications of VOC emissions are present. The leak definition is 

an instrument meter reading, in parts per million based on a reference compound. Decreasing the 

leak definition generally increases the number of leaks found during a monitoring period, which 

generally increases the number of leaks that are repaired. 

The 2012 NSPS STSD calculated incremental emission reductions from the baseline

requirements (assuming that an LDAR program equivalent to the subpart VV/subpart KKK 

LDAR program is currently implemented at natural gas processing plants), and the leak frequency

 

138 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil 

and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support 

Document for the Final New Source Performance Standards. April 2012. EPA Docket Number EPA-HQ-OAR2010-0505-4550.
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and emission factors from a supporting document for the Equipment Leak Uniform Standards

were used to calculate the emission reductions and costs. The natural gas processing plant 

component counts (see Table 8-2) were obtained from a EPA/GRI document.139 The incremental 

VOC emission reductions for implementing a subpart VVa leak detection and repair program (as 

determined in the 2012 NSPS STSD) for the natural gas processing model plant was calculated 

to be 13 percent. 

Cost Impacts

Table 8-5 presents a summary of the incremental capital and annual costs and the cost of 

control (estimated in the 2012 NSPS STSD) from baseline (subpart VV) to implementing subpart 

VVa for the gas processing model plant. The costs obtained from the 2012 NSPS STSD have 

been converted to 2012 dollars from 2008 dollars using the Federal Reserve Economic Data 

GDP Price Deflater (Change in GDP: Implicit Price Deflator from 2008 to 2012 (5.69 

percent)).

140

Table 8-5. Summary of the Gas Processing Model Plant VOC Cost of Control 

for the Subpart VVa Option

Annual VOC 

Emission Reductions

(tpy)

Capital Costs

($2012)

Annual Costs

($2012/year)

VOC Cost of Control

($2012/ton)

Without savings With 

savingsa

4.56 $8,499 $12,959 $2,844 $2,010

a With savings calculated assuming the natural gas (82.9% methane) from the methane reduction has a value of $4/Mscf. The 

VOC/methane ratio was assumed to be 0.278.

Table 8-6 provides a summary of the capital and annual costs and the cost of control on a 

component basis for the natural gas processing model plant.

 

139 GRI/EPA Research and Development. Methane Emissions from the Natural Gas Industry; Volume 8: Equipment 

Leaks. June 1996. EPA-600/R-96-080h.

140 U.S. Bureau of Economic Analysis, Gross Domestic Product: Implicit Price Deflator (GDPDEF], retrieved from 

FRED, Federal Reserve Bank of St. Louis https://research.stlouisfed.org/fred2/series/GDPDEF March, 

26, 2015.
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Table 8-6. Summary of the Gas Processing Component VOC Cost of Control 

for the Subpart VVa Option

Component

Annual VOC 

Emission 

Reductions

(tpy)

Capital 

Costs

($2012)

Annual Costs

($2012/year)

VOC Cost of Control

($2012/ton)

Without 

Savings

With 

Savingsa

Valves 1.82 $5,231 $9,280 $5,095 $4,261

Connectors 2.74 $8,374 $4,405 $1,610 $776

a With savings calculated assuming the natural gas (82.9 percent methane) from the methane reduction has a value of $4/Mscf. 

The VOC/methane ratio was assumed to be 0.278.

8.3.1.2 Leak Detection and Repair Program with Optical Gas Imaging

Another option to control VOC emissions is the implementation of a program that uses 

OGI to detect equipment leaks. This option is currently available as an alternative work practice 

(40 CFR part 60, subpart A) for monitoring emissions from equipment leaks in subpart VVa. The 

alternative work practice requires monthly monitoring of all equipment using OGI and an annual 

monitoring of all equipment using a Method 21 monitoring device. Method 21 monitoring allows 

the facility to determine the concentration of a leak and to then use emission factors found in the 

EPA’s emissions leak protocol to quantify emissions from equipment leaks, since the OGI 

system can only provide the presence of the equipment leaks. A more detailed description of, and 

the cost of implementing LDAR with OGI program for the natural gas processing model plant is 

presented in the following paragraphs.

Description

The alternative work practice for equipment leaks in §60.18 of 40 CFR part 60, subpart A 

allows the use of an OGI system to monitor equipment leaks. This LDAR program requires 

monthly monitoring and repair of components using OGI and annual monitoring of equipment

using a Method 21 instrument. This requirement does not have a leak definition because OGI can 

only measure the presence of a leak and not the concentration. Compressors are not included in 

this LDAR option and are discussed in chapter 5 of this document.

Effectiveness

No data were found on the control effectiveness of the alternative work practice. For 

purposes of this analysis, we assumed that this option would provide the same control 

effectiveness as the subpart VVa monitoring program. Therefore, the control effectiveness values 
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for implementing an alternative work practice were assumed to be 93.6 percent for valves, 95.9 

percent for connectors, 100 percent for open-ended lines, and 100 percent for pressure relief 

devices. 

Cost Impacts

The 2011 NSPS TSD calculated costs using procedures developed for estimating capital 

and annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing 

industry. Costs obtained from the 2011 NSPS TSD have been converted to 2012 dollars from 

2008 dollars using the Federal Reserve Economic Data GDP Price Deflater (Change in GDP: 

Implicit Price Deflator from 2008 to 2012 (5.69 percent)).

141 It was assumed that a single OGI 

device and a single Method 21 monitoring device could be used at multiple locations. To 

calculate the shared cost of OGI and the Method 21 devices, the time required to monitor a single 

facility was estimated. It was assumed for gas processing facilities that the full cost of the OGI 

system and the Method 21 monitoring device would apply to each individual plant. Assuming a 

20-day work month, the total number of facilities that could be monitored by a single OGI 

system and Method 21 device is 80. Therefore, the shared cost of the Method 21 monitoring 

device was calculated to be $1,209 per site. 

Table 8-7 presents a summary of the capital and annual costs and the VOC cost of control 

for the natural gas processing model plant using the alternative work practice monitoring. A cost 

of control analysis on a component basis for the alternative work practice was not performed 

because the OGI system is intended for facility-wide monitoring.

Table 8-7. Summary of the Natural Gas Processing Model Plant VOC Cost of Control for 

Optical Gas Imaging and Method 21 Monitoring

Annual VOC 

Emission 

Reductions

(tpy)

Capital 

Costs

($2012)

Annual Costs

($2012/year)

VOC Cost of Control

($2012/ton)

Without 

Savings

With 

Savings

4.56 $97,787 $92,013 $20,192 $19,358

 

141 U.S. Bureau of Economic Analysis, Gross Domestic Product: Implicit Price Deflator (GDPDEF), retrieved from 

FRED, Federal Reserve Bank of St. Louis https://research.stlouisfed.org/fred2/series/GDPDEF March, 

26, 2015.
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8.3.2 Existing Federal, State and Local Regulations

8.3.2.1 Federal Regulations that Specifically Require Control of VOC 

Emissions

Federal regulations that regulate VOC emissions from equipment leaks at natural gas 

processing plants include the 2012 NSPS, subpart KKK and the 1983 CTG (established a 

recommended RACT for VOC for natural gas processing plants at a level of control equivalent 

to subpart KKK).

8.3.2.2 State and Local Regulations that Specifically Require Control of VOC 

Emissions

States may have permitting restrictions on VOC emissions that may apply to an 

emissions source as a result of an operating, NSR NA, or PSD permit (e.g., on a case-by-case 

basis) based on air quality maintenance or improvement goals of an area. Permits specify what 

construction is allowed, what emission limits must be met, and often how the source must be 

operated. To assure that sources follow the permit requirements, permits also contain monitoring, 

recordkeeping, and reporting requirements. 

We assume that all states currently regulate equipment leaks (except compressors) at 

existing natural gas processing plants at the 1983 CTG and subpart VV level of control.

8.4 Recommended RACT Level of Control for Equipment Leaks from 

Equipment at Natural Gas Processing Plants

As discussed in section 8.3.2 of this chapter, existing federal and state and local 

regulations already require the reduction of VOC emissions using an LDAR program. The 2012 

NSPS requires a 40 CFR part 60 subpart VVa LDAR monitoring program for processing plants. 

The 2012 NSPS reported a cost of control for natural gas processing plants to be $2,844 per ton 

of VOC removed for the 40 CFR part 60 subpart VVa option, and $20,192 per ton of VOC 

removed for the Method 21/OGI option. The option for just monitoring just valves or connectors 

at the 40 CFR part 60 subpart VVa level of control was estimated to be $5,095 and $1,610 per 

ton of VOC removed, respectively.

Based on costs and existing LDAR programs that are already employed at natural gas 

processing plants, we recommend that RACT for natural gas processing plants be the 

implementation of an LDAR program equivalent to what is required under 40 CFR part 60 
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subpart VVa for equipment (with the exception of compressors) in VOC service. This RACT 

recommendation would increase the stringency from the currently implemented LDAR programs 

at most existing natural gas processing plants (that were built prior to 2012) in VOC service by 

lowering the leak definitions, increasing the monitoring frequency and including additional 

components. The subpart VVa leak detection and repair program requires the annual monitoring 

of connectors using an OVA or TVA (500 ppm leak definition), monthly monitoring of valves 

(500 ppm leak definition) and requires open-ended lines and pressure relief devices to operate 

with no detectable emissions (500 ppm leak definition). The estimated annual incremental VOC 

emission reductions for the recommended RACT for a natural gas processing plant was 

estimated to be 4.56 tpy (see Table 8-5 of this chapter). The annual VOC emission reductions 

assume a baseline level of control equivalent to the 40 CFR part 60, subpart VV LDAR program. 

Table 8-5 presents the gas processing model plant VOC cost of control for the recommended 

RACT. The costs assume a baseline level of control equivalent to the 40 CFR part 60, subpart 

VV LDAR program. The recommended RACT VOC cost of control is estimated to be $2,844

per ton of VOC reduced without savings and $2,010 with savings. 

In summary, we recommend the following RACT for equipment leaks at natural gas 

processing plants:

RACT for Equipment Leaks at Natural Gas Processing Plants: We recommend the 

implementation of an LDAR program equivalent to what is required under 40 CFR part 

60 subpart VVa for equipment components (with the exception of compressors) in VOC 

service.

8.5 Factors to Consider in Developing Equipment Leak Compliance 

Procedures 

Existing natural gas processing plants that would be subject to the recommend RACT are 

already subject to an LDAR program and the basic elements of the LDAR program for the 

facility are in place. However, the LDAR program would need to be modified to increase the 

stringency from the currently implemented LDAR program by lowering the leak definitions, and 

to require annual monitoring of connectors using an OVA or TVA (500 ppm leak definition), 

monthly monitoring of valves (500 ppm leak definition) and to require open-ended lines and 

pressure relief devices to operate with no detectable emissions (500 ppm leak definition). As 

with the currently implemented LDAR program, to ensure that equipment in VOC service that 
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Equipment Leaks

leak at natural gas processing plants are properly monitored and repaired under the LDAR RACT 

recommendations, we suggest that regulatory agencies specify monitoring and equipment 

component repair recordkeeping and reporting requirements to document compliance. 

Monitoring intervals vary according to the applicable regulation, but are typically

weekly, monthly, quarterly, and yearly. The monitoring interval depends on the equipment type 

and periodic leak rate for the equipment. For each piece of equipment that is found to be leaking, 

the first attempt at repair should be made within a reasonable period of time, such as no later 

than five calendar days after each leak is detected. First attempts at repair include, but are not 

limited to, the following best practices, where practicable and appropriate:

(1) Tightening of bonnet bolts;

(2) Replacement of bonnet bolts;

(3) Tightening of packing gland nuts and

(4) Injection of lubricant into lubricated packing.

Once the equipment is repaired, it should be monitored over the next several days to ensure the 

leak has been successfully repaired. Another method that can be used to repair equipment is to 

replace the leaking equipment with a “leakless” equipment or other technologies. 

When implementing an LDAR program, we recommend that regulatory agencies 

consider including recordkeeping requirements that require owner/operators of subject facilities 

to maintain a list of identification numbers for all equipment subject to an equipment leak 

regulation. A list of equipment that is designated as “unsafe to monitor” should also be 

maintained with an explanation/review of conditions for the designation. Detailed schematics, 

equipment design specifications (including dates and descriptions of any changes), and piping 

and instrumentation diagrams should also be maintained with the results of performance testing 

and leak detection monitoring.

The appendix to this document presents example model rule language that incorporates 

compliance elements recommended in this section that states may choose to use in whole or in 

part when implementing RACT.
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9-1

Fugitive Emissions

9.0 FUGITIVE EMISSIONS FROM WELL SITES AND COMPRESSOR

STATIONS

Fugitive emissions from components in the oil and natural gas industry are a source of 

VOC emissions. This chapter discusses the sources of fugitive emissions, and provides VOC 

emission estimates for well sites and compressor stations in the production segment (located 

from the wellhead to the point of custody transfer to the natural gas transmission and storage 

segment or point of custody transfer to an oil pipeline). This chapter also presents a description 

of programs that are designed to reduce fugitive emissions, along with costs and emission 

reductions. Finally, this chapter provides a discussion of our recommended RACT and the 

estimated VOC emission reductions and costs for fugitive emissions from well sites and 

compressor stations. 

9.1 Applicability

For purposes of this guideline, the emissions and programs to control emissions discussed 

herein would apply to the collection of fugitive emissions components at a well site with an 

average production of greater than 15 barrel equivalents per well per day (15 barrel equivalents), 

and the collection of fugitive emissions components at compressor stations in the production 

segment. It is our understanding that fugitive emissions at a well site with low production wells 

are inherently low and that many well sites are owned and operated by small businesses. We are 

concerned about the burden of the fugitive emissions recommendation on small businesses, in 

particular where there is little emission reduction to be achieved. For the purposes of this 

guideline, fugitive emissions recommendations would not apply to well sites that only contain 

wellheads.

Fugitive emissions, for the purposes of applicability of this guideline, means those 

emissions from a stationary source that could not reasonably pass through a stack, chimney, vent, 

or other functionally equivalent opening. Equipment leak emissions at natural gas processing 

plants are covered under chapter 8 of this document.
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Fugitive Emissions

9.2 Fugitive Emissions Description and Data

9.2.1 Fugitive Emissions Description

There are several potential sources of fugitive emissions throughout the oil and natural 

gas industry. Fugitive emissions occur when connection points are not fitted properly or when 

seals and gaskets start to deteriorate. Changes in pressure, temperature or mechanical stresses 

can also cause fugitive emissions from components. Fugitive emission components are defined 

as any component that has the potential to emit fugitive emissions at a well site or gathering and 

boosting station. These components include valves, connectors, pressure relief devices, openended lines (OEL), access doors, flanges, closed vent systems, thief hatches or other openings on 

storage vessels, agitator seals, distance pieces, crankcase vents, blowdown vents, pump seals or 

diaphragms, compressors, separators, pressure vessels, dehydrators, heaters, instruments, and 

meters. Devices that vent as part of normal operations, such as natural gas-driven pneumatic 

controllers or natural gas-driven pumps, are not fugitive emissions components, insofar as the 

natural gas discharged from the device’s vent is not considered a fugitive emission. Emissions 

originating from other than the vent, such as seals around the bellows of a diaphragm pump, 

would be considered fugitive emissions.

In April of 2014, the EPA published a white paper titled “Oil and Natural Gas Sector 

Leaks”142 that summarized the EPA current understanding of fugitive emissions at oil and natural 

gas production, processing and transmission facilities (referred to herein as the “equipment leaks 

white paper”). The equipment leaks white paper identified 12 studies or publicly available 

sources that provided fugitive emission estimates from the various segments of the oil and 

natural gas industry. Many of the fugitive emission measurements were conducted with EPA 

Method 21 instruments. In addition to EPA Method 21 analyzers, several studies conducted 

fugitive emission surveys using OGI in conjunction with portable Method 21 analyzers and gas 

chromatograph equipment to measure individual VOC compounds. These studies provided 

emission estimates in the form of component or equipment emission factors or emission 

estimates by facility. Fugitive emission estimates for VOC ranged from 0.4 to 10 tpy for oil and 

 

142 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Leaks, Office of Air Quality Planning and 

Standards. Research Triangle Park, NC. April 2014. Available at

http://www.epa.gov/airquality/oilandgas/2014papers/
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Fugitive Emissions

natural gas production sites. Even though there is a wide variation in the VOC emissions 

estimates, the studies showed that there are viable options for reducing these emissions. 

9.2.2. Emission Data and Emission Factors

9.2.2.1 Summary of Major Studies and Emission Factors

The equipment leaks white paper provided a summary of fugitive emission studies at oil 

and natural gas production and compressor stations in the production segment. When we 

evaluated the emissions and emission reduction options for equipment leaks, many of these 

studies in the white paper were consulted. Table 9-1 presents a list of the studies consulted along 

with an indication of the type of information contained in the study.

9.2.2.2 Model Plants

Facilities in the oil and natural gas industry consist of a variety of combinations of 

process equipment and components. This is particularly true in the production segment of the 

industry, where “surface sites” can vary from sites where only a wellhead and associated piping 

is located to sites where a substantial amount of separation, treatment, and compression occurs. 

In order to conduct analyses to be used in evaluating potential options to reduce fugitive 

emissions from well sites and gathering and boosting stations, a model plant approach was used. 

The following sections discuss the creation of these model plants.

We obtained information related to equipment counts for natural gas well sites and 

gathering and boosting stations from the EPA/GRI natural gas industry study143. This document 

also provided average component counts for equipment in the natural gas production segment. 

The types of components that are associated with this equipment include: valves, connectors, 

open-ended lines, and pressure relief valves. These average counts were used to develop an 

average model plants for well sites in the production segment of the industry and for a gathering 

and boosting station. Equipment counts associated with oil well sites were obtained from an API 

Workbook. These equipment counts are consistent with those contained in the EPA’s analysis to 

estimate methane emissions conducted in support of the GHGRP. These model plants are 

discussed in the following sections. 

 

143 Gas Research Institute (GRI)/U.S. Environmental Protection Agency. Research and Development, Methane 

Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. June 1996 (EPA-600/R-96-080h).
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Fugitive Emissions
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Fugitive Emissions

Table 9-1. Major Studies Reviewed for Emissions and Activity Data

Report Name Affiliation Year of 

Report

Activity

Factors

Emissions 

Data

Control 

Options

Protocol for Equipment Leak 

Emission Estimatesa EPA 1995 None X X

Methane Emissions from the 

Natural Gas Industry: 

Equipment Leaksb

EPA/GRI 1996 Nationwide X X

Greenhouse Gas Reporting 

Programc EPA 2013 Facility X

Inventory of Greenhouse 

Gas Emissions and Sinks: 

1990-2012d

EPA 2014 Regional X

Measurements of Methane 

Emissions at Natural Gas 

Production Sites in the 

United Statese

Multiple 

Affiliations, 

Academic and 

Private

2013 Nationwide X X

City of Fort Worth Natural 

Gas Air Quality Study, Final 

Reportf

City of Fort 

Worth 2011 Fort Worth, TX X X

Measurements of Well Pad 

Emissions in Greeley, COg

ARCADIS/Sa

ge 

Environmental 

Consulting/ 

EPA

2012 Colorado X X

Quantifying CostEffectiveness of Systematic 

Leak Detection and Repair 

Programs Using Infrared 

Camerash

Carbon Limits 2013 Canada and 

the U.S. X X

Mobile Measurement 

Studies in Colorado, Texas, 

and Wyomingi

EPA 2012 and 

2014

Colorado, 

Texas, and 

Wyoming

X X

Economic Analysis of 

Methane Emission 

Reduction Opportunities in 

the U.S. Onshore Oil and 

Natural Gas Industriesj

ICF 

International 2014 Nationwide X X

Identification and Evaluation 

of Opportunities to Reduce 

Methane Losses at Four Gas 

Processing Plantsk

Clearstone 

Engineering, 

Ltd.

2002

4 gas 

processing 

plants

X X
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9-6

Fugitive Emissions

Report Name Affiliation Year of 

Report

Activity

Factors

Emissions 

Data

Control 

Options

Cost-Effective Directed 

Inspection and Maintenance 

Control Opportunities at 

Five Gas Processing Plants 

and Upstream Gathering 

Compressor Stations and 

Well Sitesl

Clearstone 

Engineering, 

Ltd.

2006

5 gas 

processing 

plants, 12 

well sites

X X

a U.S. Environmental Protection Agency. Protocol for Equipment Leak Emission Estimates. Office of Air Quality Planning and 

Standards. Research Triangle Park, NC. November 1995. EPA-453/R-95-017. Available at 

http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf.

b U.S. Environmental Protection Agency/GRI. Research and Development, Methane Emissions from the Natural Gas Industry, 

Volume 8: Equipment Leaks. June 1996 (EPA-600/R-96-080h).

c U.S. Environmental Protection Agency. Greenhouse Gas Reporting Program. (Annual Reporting; Current Data Available for 

2011-2013). 2014.

d. U.S. Environmental Protection Agency. Inventory of Greenhouse Gas Emissions and Sinks: 1990-2011. Climate Change 

Division, Washington, DC. April 2013. Available at http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHGInventory-2013-Chapter-3-Energy.pdf.

e.Allen, David, T., et al. Measurements of methane emissions at natural gas production sites in the United States. Proceedings of 

the National Academy of Sciences (PNAS) 500 Fifth Street, NW NAS 340 Washington, DC 20001 USA. October 29, 2013. 6 

pgs. Available at http://www.pnas.org/content/early/2013/09/10/1304880110.full.pdf+html. 

f. ERG and Sage Environmental Consulting, LP. City of Fort Worth Natural Gas Air Quality Study, Final Report. Prepared for 

the City of Fort Worth, Texas. July 13, 2011. Available at http://fortworthtexas.gov/gaswells/default.aspx?id=87074.

g. Modrak, Mark T., et al. Understanding Direct Emissions Measurement Approaches for Upstream Oil and Gas Production 

Operations. Air and Waste Management Association 105th Annual Conference and Exhibition, June 19-22, 2012 in San Antonio, 

Texas.

h

. Carbon Limits. Quantifying cost-effectiveness of systematic Leak Detection and Repair Programs using Infrared cameras. 

December 24, 2013. Available at http://www.catf.us/resources/publications/files/CATFCarbon_Limits_Leaks_Interim_Report.pdf.

i. Thoma, Eben D., et al. Assessment of Methane and VOC Emissions from Select Upstream Oil and Gas Production Operations 

Using Remote Measurements, Interim Report on Recent Studies. Proceedings of the 105th Annual Conference of the Air and 

Waste Management Association, June 19-22, 2012 in San Antonio, Texas.

j.ICF International. Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas 

Industries. ICF International (Prepared for the Environmental Defense Fund). March 2014.

k. Clearstone Engineering Ltd. Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas Processing 

Plants. June, 2002.

l. Clearstone Engineering Ltd. Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing 

Plants and Upstream Gathering Compressor Stations and Well Sites. March, 2006.

Well Sites

Oil and natural gas production varies from one site to the next. Some production sites 

may include only a single wellhead that is extracting oil or natural gas from the ground, while 

other sites may include multiple wellheads attached to a well site. A well site is a site where the 

production, extraction, recovery, lifting, stabilization, separation and/or treating of petroleum 

and/or natural gas (including condensate) occurs. These sites include all equipment (including 

piping and associated components, compressors, generators, separators, storage vessels, and 
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Fugitive Emissions

other equipment) associated with these operations. A well site can serve one well on a pad or 

multiple wells on a pad. Therefore, the number of components with potential for fugitive 

emissions can vary depending on the number of wells feeding into the production pad and the 

amount of processing equipment located at the site. 

We used equipment count data from the EPA GHG Inventory to calculate the average 

counts of production equipment located at a well site. The types of production equipment located 

at a well site include: gas wellheads, separators, meters/piping, heaters, and dehydrators. The 

types of components that are associated with this equipment include: valves, connectors, openended lines, and pressure relief valves. Component counts for each of the equipment items were

calculated using the average component counts for gas production equipment in the Eastern U.S 

and the Western U.S. for the EPA/GRI document. 

A model plant was developed using the average number of wells associated with a well 

site using data from the Drillinginfo HPDI database.

145 Baseline fugitive emissions from well 

sites depend upon the quantity of equipment and components, which in turn is based on this 

estimate of wells per pad. To estimate the average number of wells co-located on the same site as 

a new well completion or recompletion, the EPA developed a pair of algorithms that identified 

new and existing wells within a given distance of a new well completion or recompletion. This 

distance was assumed to represent the distance that, if other wells were within the distance, the 

wells would likely be co-located with the well under examination on the same site. The 

algorithms were written in the open source R programming language.146

The HPDI well and production data used to estimate the average number of well colocated on a well site drew upon the latitude and longitude of new well completions and 

recompletions as well as the coordinates of all wells producing oil or natural gas in 2012. The 

first algorithm estimated the distances between each new completion and recompletion and all 

producing wells, which also includes wells newly completed and producing in 2012 within the 

same county as the completed well. If the distance between the completed well and producing 

well was less than the assumed size of a typical well site, we assumed the two wells were colocated. This algorithm progressed county by county across the U.S. where oil and natural gas

 

145 Drilling Information, Inc. 2011. DI Desktop. 2011 Production Information Database.

146 See the website <http://www.r-project.org/> for more information on R (The R Project for Statistical 

Computing). R is a free software environment for statistical computing and graphics.
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production occurred in 2012 to identify all co-located wells in the U.S. The number of new well 

completions and recompletions in 2012 was about 44,000, which includes oil and natural gas

wells whether they were hydraulically fractured or not. All wells producing in 2012 numbered 

about 1.27 million. The second algorithm processed the results of the first such that a well can 

only appear once on a modelled well site. 

Once these algorithms were complete and produced a results file, we converted the 

results into a “kml” file that enabled the visual inspection of the results within Google Earth. We 

did not visually inspect every site in the U.S. linked to a 2012 completion or recompletion as 

they numbered greater than 20,000. Instead, we examined sites randomly across a range of oil 

and natural gas production regions. The results of this visual examination indicated the 

algorithms were functioning as intended.

We estimated the number of wells per site assuming sites of one, two and three acres, 

based upon input from petroleum industry data analysts. Table 9-2 shows the high-level results 

of these analyses.

Table 9-2. Estimated Average Number of Wells per Site of New Well Completion in 2012 

Assumed Well Site Size

No. of 

Well Sites

No. of 

Wells at Sites

Average of Wells 

Per Site

One Acre 29,213 50,599 1.73

Two Acres 28,938 52,422 1.81

Three Acres 28,710 53,981 1.88

For assumed well sites of two acres, the analysis identified 28,938 independent well sites 

that contained 52,422 wells (including both single and multi-well sites). The total number of 

wells identified as being co-located with new well completions and recompletions exceeds the 

total number of completions and recompletions because the sites include about 8,500 existing 

wells producing in 2012.

However, the high level summary presented in Table 9-3 masks variation by basins and 

well types. Table 9-3 presents more detail along these dimensions for the assumed two-acre well 

site.
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Table 9-3. Estimated Average Number of Wells per Two Acre Site of New Well Completion 

and Recompletion in 2012, by HPDI Basin and Type of Well (Oil or Natural Gas, 

Hydraulically Fractured or Not)

Oil Well 

Completions

Natural Gas Well 

Completions

HPDI Basin

No. Of 

Sites HF

Not 

HF All HF

Not 

HF All Total

Los Angeles 23 N/A 13.07 13.07 N/A N/A N/A 13.07

Piceance 111 2.00 1.00 1.75 6.72 11.75 10.14 9.84

Arctic Ocean 2 N/A 5.50 5.50 N/A N/A N/A 5.50

Green River 164 2.23 1.57 2.01 4.37 1.13 4.19 3.88

Unidentified 226 1.18 3.57 3.38 1.00 1.77 1.44 3.22

San Joaquin Basin 1,745 1.56 3.46 3.21 2.61 1.42 2.24 3.16

Arkoma Basin 374 4.00 1.33 2.00 3.06 1.00 3.01 3.00

Denver Julesburg 826 2.63 3.10 2.75 1.48 3.14 1.72 2.46

Ft Worth Basin 1,305 2.05 1.86 1.91 3.27 1.10 2.93 2.33

Central Western Overthrust 7 1.50 N/A 1.50 2.60 N/A 2.60 2.29

Ventura Basin 1 N/A 2.00 2.00 N/A N/A N/A 2.00

Arctic Slope 42 N/A 2.13 2.13 N/A 1.65 1.65 1.99

Ouachita Folded Belt 181 2.01 1.90 1.99 1.50 1.00 1.43 1.97

Salina Basin 13 N/A 1.92 1.92 N/A N/A N/A 1.92

Palo Duro Basin 81 1.42 1.97 1.89 1.00 N/A 1.00 1.86

Uinta 548 1.16 1.33 1.32 N/A 3.33 3.33 1.83

Texas & Louisiana Gulf Coast 3,994 2.03 1.82 1.96 1.37 1.14 1.28 1.79

Central Kansas Uplift 450 N/A 1.78 1.78 N/A 1.53 1.53 1.77

Permian Basin 8,507 1.66 1.76 1.69 1.50 1.57 1.52 1.68

Sedgwick Basin 240 N/A 1.67 1.67 1.67 1.55 1.55 1.62

Las Animas Arch 25 1.00 1.64 1.61 N/A 1.50 1.50 1.60

Nemaha Anticline 38 N/A 1.55 1.55 N/A N/A N/A 1.55

Arkla Basin 811 1.09 1.57 1.49 1.47 1.09 1.42 1.46

Chautauqua Platform 461 1.36 1.57 1.49 1.64 1.03 1.35 1.45

Cook Inlet Basin 9 N/A 2.00 2.00 N/A 1.29 1.29 1.44

Appalachian 2,496 1.14 1.05 1.10 2.28 1.10 1.77 1.43

Williston 1,570 1.36 1.00 1.35 1.43 1.00 1.39 1.35

Cherokee Basin 271 1.17 1.29 1.29 N/A 1.69 1.69 1.35

San Juan 158 1.00 1.00 1.00 1.38 1.20 1.37 1.31

East Texas Basin 618 1.25 1.74 1.52 1.22 1.06 1.21 1.31

Forest City Basin 172 N/A 1.28 1.28 N/A N/A N/A 1.28

Anadarko Basin 2,663 1.17 1.77 1.37 1.09 1.29 1.13 1.27

South Oklahoma Folded Belt 167 1.17 1.36 1.30 1.11 1.11 1.11 1.24

Chadron Arch 49 N/A 1.22 1.22 N/A N/A N/A 1.22
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Oil Well 

Completions

Natural Gas Well 

Completions

HPDI Basin

No. Of 

Sites HF

Not 

HF All HF

Not 

HF All Total

Sacramento Basin 13 N/A N/A N/A N/A 1.15 1.15 1.15

Mississippi & Alabama Gulf Coast 132 1.00 1.18 1.14 1.00 1.00 1.00 1.14

Central Montana Uplift 10 1.13 1.00 1.10 N/A N/A N/A 1.10

Big Horn 30 1.10 1.11 1.11 1.00 N/A 1.00 1.10

Powder River 232 1.15 1.03 1.12 1.05 1.00 1.04 1.10

Sweet Grass Arch 17 1.00 1.08 1.05 1.50 1.00 1.33 1.10

Paradox 13 1.00 1.10 1.09 1.00 N/A 1.00 1.08

Black Warrior Basin 57 1.00 1.00 1.00 1.00 1.75 1.07 1.05

Wind River 63 1.00 1.02 1.02 1.00 1.00 1.00 1.02

Wasatch Uplift 1 N/A 1.00 1.00 N/A N/A N/A 1.00

North Park 2 1.00 1.00 1.00 N/A N/A N/A 1.00

Raton 20 N/A N/A N/A 1.00 1.00 1.00 1.00

Grand Total 28,938 1.64 1.99 1.79 1.90 1.76 1.86 1.81

Table 9-3 provides data that the concentration of wells at production sites varies greatly

by basin. However, the analysis indicates that most wells sites have relatively few or no colocated wells, which brings the national average wells per new completion or recompletion site 

to 1.81 for the two-acre well site. While the analysis shows variation by basin, at the nationallevel, there is relatively little variation across oil and natural gas well completion sites and 

whether the new wells were completed or recompleted using hydraulic fracturing. For example, 

oil well sites averaged 1.79 wells per site while natural gas wells averaged 1.86. 

As a result of this analysis, based upon professional judgment, we decided to use the twoacre well site as the assumed maximum size of a site to estimate the number of wells co-located 

at sites of new completions and recompletions. Also, to simplify analysis of costs and emissions 

at well sites, we rounded the 1.81 national average wells per site to 2.

While we are confident that the assumed two acre well site is a reasonable size to capture 

most co-located wells in 2012, it is by no means a perfect assumption. First, industry and state 

regulatory trends indicate that well drilling will likely become increasingly concentrated on sites, 

potentially leading to an increase in the average number of wells per well site. However, it is not 

possible at this point to forecast this increasing concentration, especially with the variations by 

fields described above. Also, it is possible that two acres is too small to accurately estimate the 
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number of co-located wells for large well sites in some fields. As a result, the algorithms might 

result in an under-estimate of the average number of wells at a site and identify more than one 

site when in actuality there is only one. Alternatively, the assumed two acres might over-estimate 

the size of sites in some fields and, as a result, pull in more than one site, overestimating the 

number of wells on the site. We also noted that the latitude and longitude values on many wells 

were likely incorrect or exact duplicates of other wells. Despite these caveats, we believe that the 

well site analysis described here produces a reasonable estimate of national average of number of 

wells on new well completion and recompletion sites in 2012. Therefore, based on this analysis, 

the model plant for an oil and natural gas production site was based on a well site with 2 wells. 

For natural gas well sites, the model plant was developed using the average equipment 

and fugitive emissions components counts for gas production data from the EPA/GRI report. The 

average equipment count for a gas well was estimated by weighting the average of equipment 

counts for the Eastern and Western U.S. data sets for gas production equipment. The weighted 

averages of the data sets were determined to be 1.6 separators, 0.8 meters/piping, 0.8 in-line 

heaters, and 0.6 dehydrators per well. The total natural gas well site equipment counts were 

calculated by multiplying the average well equipment values by the average number of wells per 

well site (2), and rounding the product to the nearest integer. Average component counts for each 

of the equipment items were calculated using the average component counts for production 

equipment in the Eastern U.S and the Western U.S. from the EPA/GRI study. The total number 

of fugitive emissions components was calculated by multiplying the rounded equipment counts 

by the component count per equipment and rounding to the nearest integer. Table 9-4 presents a 

summary of the fugitive emissions component counts for natural gas well sites.

For oil well sites, the model plant was developed using equipment counts from an API workbook 

and component count data from the EPA/GRI study. The average equipment count for an oil well 

were determined to be 0.7 separators, 0.7 headers, and 0.03 heater/treaters per well. The total oil 

well site equipment counts were calculated by multiplying the average well equipment values by

the average number of oil wells per oil well site (2), and rounding the product to the nearest 

integer. Average component counts obtained from the API workbook were used to calculate the 

total number of components by multiplying the rounded equipment counts by the component 

count per equipment and rounding up to the nearest integer. Table 9-5 presents a summary of the 

fugitive emissions component counts for oil well sites.
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Table 9-4. Average Component Count for Natural Gas Well Site Model Plant

Equipment Model Plant 

Equipment Counts

Average Component Count per Equipmenta Average Component Count per Model 

Plant

Valves Connectors OELs PRVs Valves Connectors OELs PRVs

Gas 

Wellheads 2 9 37 1 0 19 74 1 0

Separators 2 22 68 4 1 43 137 7 2

Meters/Piping 1 13 48 0 0 13 48 0 0

In-Line 

Heaters 1 14 65 2 1 14 65 2 1

Dehydrators 1 24 90 2 2 24 90 2 2

Total 113 414 12 5

Rounded up Total 114 414 14 6

a Data Source: EPA/GRI, CH4 Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-080h)

Table 9-5. Average Component Count for Oil Well Site Model Plant

Equipment

Model Plant 

Equipment 

Counts

Average Component Count per Equipmenta Average Component Count per Model Plant

Valves Connectors OELs PRVs Valves Connectors OELs PRVs

Oil Wellheads 2 5 18 0 0 10 36 0 0

Separators 1 6 22 0 0 6 22 0 0

Headers 1 5 14 0 0 5 14 0 0

Heater/Treaters 1 8 32 0 0 8 32 0 0

Total 29 104 0 0

Rounded up Total 29 104 1 1

a Data Source: EPA/GRI, CH4 Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-08
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Baseline emissions for the natural gas well site model plant were calculated using the 

equipment and fugitive emissions component counts and the representative gas service emission 

factors. Emissions were estimated using the EPA Protocol which provided total organic 

compound (TOC) emission factors for production sources (well sites, gathering and boosting).

Annual emissions were calculated assuming 8,760 hours of operation each year. Table 9-6 

presents the emission factors for the natural gas and oil production segments.

Emissions of VOC were calculated using weight ratios for VOC as described in the 2000 Gas 

Composition Memorandum developed for the 2012 NSPS149. A summary of the equipment 

counts, and average TOC emission factors and VOC emissions for natural gas and oil well sites 

are provided in Tables 9-7 and 9-8, respectively. Using these data, the average fugitive emissions 

from a gas well model plant was determined to be 1.26 tpy of VOC and the average fugitive 

emissions from an oil well model plant was determined to be 0.302 tpy of VOC. The VOC 

emission estimates were used to evaluate the potential emission reductions and cost of control of 

a fugitive emissions reduction program.

Table 9-6. Oil and Natural Gas Production Operations Average TOC Emission Factors

Component Type Component 

Service

TOC Emission 

Factora

(kg/hr/source)

Valves Gas 4.5E-03

Connectors Gas 2.0E-04

OEL Gas 2.0E-03

PRV Gas 8.8E-03

a Data Source: EPA, Protocol for Equipment Leak Emission Estimates, Table 2-4, 

November 1995. (EPA-453/R-95-017)

 

149 Memorandum to Bruce Moore from Heather Brown. Composition of Natural Gas for Use in the Oil and Natural 

Gas Sector Rulemaking. EC/R, Incorporated. July, 2011.
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Table 9-7. Estimated Fugitive VOC Emissions for Natural Gas Production Model Plant

Natural Gas Well 

Site Model Plant 

Component

Model Plant 

Component 

Counta

Uncontrolled 

TOC Emission 

Factorb

(kg/hr/comp)

Uncontrolled VOC 

Emissions

(tpy)c

Valves 114 0.0045 0.957

Connectors 414 0.0002 0.154

OELs 14 0.002 0.052

PRVs 6 0.0088 0.098

Total 1.26

a Component count values for model plant are based on a 2 wellhead pad and are rounded to the nearest integer.

b TOC emission factors obtained from Table 2-4 for the EPA Equipment Leaks Protocol for components in gas service.

c VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from the 2011 Gas Composition 

Memorandum.

Table 9-8. Estimated Fugitive VOC Emissions for Oil Well Site Model Plant

Natural Gas Well 

Site Model Plant 

Component

Model Plant 

Component 

Counta

Uncontrolled 

TOC Emission 

Factorb

(kg/hr/comp)

Uncontrolled VOC 

Emissions

(tpy)c

Valves 29 0.0045 0.243

Connectors 104 0.0002 0.039

OELs 1 0.002 0.004

PRVs 1 0.0088 0.016

Total 0.302

a Component count values for model plant are based on a 2 wellhead pad and are rounded to the nearest integer.

b TOC emission factors obtained from Table 2-4 for the EPA Equipment Leaks Protocol for components in gas service.

c VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from the 2011 Gas Composition 

Memorandum. 
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Gathering and Boosting Stations

Gathering and boosting stations are sites that collect natural gas from well sites and direct 

them to the natural gas processing plants. These stations have similar equipment to well sites; 

however they are not directly connected to the wellheads. The gathering and boosting station 

model plant was developed using the average equipment and fugitive emissions component 

counts for production from the EPA/GRI study. The average equipment counts for a gathering 

and boosting station were estimated by weighting the average of equipment counts for the 

Eastern and Western U.S. data sets for production equipment. The weighted averages of the data 

sets were determined to be 11 separators, 7 meters/piping, 5 gathering compressors, 7 in-line 

heaters, and 5 dehydrators. Fugitive emissions component counts for each of the production 

equipment items were calculated using the average component counts for production equipment 

in the Eastern U.S and the Western U.S. from the EPA/GRI study. The components for gathering 

compressors were included in the model plant total counts, but the compressor seals were 

excluded. Compressors seals are addressed in chapter 8 of this document. Table 9-9 presents a 

summary of the fugitive emissions component counts for gathering and boosting stations. 

Baseline emissions were calculated using the component counts and the TOC emission 

factors for oil and natural gas production (See Table 9-6). Table 9-10 summarizes the baseline 

emissions for gathering and boosting stations. The average fugitive emissions from a gathering 

and boosting station were determined to be 9.8 tpy of VOC. The VOC emission estimate was 

used to evaluate the potential emission reductions and cost of control of a fugitive emissions 

reduction program.
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Table 9-9. Average Component Count for the Oil and Natural Gas Production Gathering and Boosting Station Model Plant

Equipment

Model 

Plant 

Equipment 

Counts

Average Component Count per Equipmenta Average Component Count per Model Plant

Valves Connectors

OpenEnded 

Lines

Pressure 

Relief Valves Valves Connectors Open-Ended Lines

Pressure 

Relief 

Valves

Separators 11 22 68 4 1 242 748 44 11

Meters/Piping 7 13 48 0 0 91 336 0 0

Gathering 

Compressors

5 71 175 3 4 355 875 15 20

In-Line 

Heaters 7 14 65 2 1 98 455 14 7

Dehydrators 5 24 90 2 2 120 450 10 10

Total 906 2,864 83 48

a Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-080h)
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Table 9-10. Estimated Fugitive TOC and VOC Emissions for the Oil and Natural Gas

Production Gathering and Boosting Station Model Plant

Component

Model Plant 

Component 

Counta

Component TOC 

Emission Factor

(kg/hr/ component)b

VOC 

Emissions 

(tons/yr)c

Valve 906 0.0045 7.6

Connectors 2,864 0.0002 1.1

OEL 83 0.002 0.3

PRV 48 0.0088 0.8

Total 9.8

a Component counts from Table 9-7. Component count values for model plant are based on 2 wellhead sites

and are rounded to the nearest integer.

b TOC emission factors obtained from Table 2-4 for the EPA Equipment Leaks Protocol for components in gas 

service.

c VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from the 2011 Gas Composition

memorandum. 

9.3 Available Controls and Regulatory Approaches

9.3.1 Available VOC Emission Control Options

The EPA has determined that fugitive emissions from components are a significant 

source of VOC emissions from well sites and gathering and boosting stations. Based on the 

review of public and peer review comments on the equipment leaks white paper and the 

Colorado and Wyoming state rules, the EPA has identified two options for reducing fugitive 

VOC emissions from components: a fugitive emissions monitoring program based on the use of 

OGI leak detection combined with repair of fugitive emission components, and a leak monitoring 

program based on individual component monitoring using Method 21 for leak detection 

combined with repair of fugitive emission components. These options, as currently being used by 

industry to reduce fugitive emissions in the oil and natural gas industry, are described below. 

9.3.1.1 Fugitive Emission Detection and Correction with Optical Gas Imaging

Description

The reduction of fugitive emissions from well sites and gathering and boosting stations 

involves the development of a fugitive emissions monitoring plan. An example plan would 

incorporate surveying of equipment and components using OGI, which also includes operational 

requirements for the OGI instrument, along with repair, recordkeeping and reporting 

requirements. A facility can use a corporate-wide fugitive emissions monitoring plan that covers 
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the collection of fugitive emission components at well sites and gathering and boosting stations 

and a site specific fugitive emissions monitoring plan specific to each collection of fugitive 

emissions components at a well site or gathering and boosting station. Alternatively, a facility

can use a site-specific plan for each collection of fugitive emissions components at a well-site or 

gathering and boosting station that contains both the corporate-wide and site-specific plan 

elements. The monitoring plan must include inspection of fugitive emission components 

(including but not limited to valves, connectors, pressure relief devices, open-ended lines, access 

doors, flanges, closed vent systems, thief hatches or other openings on a storage vessels, agitator 

seals, distance pieces, crankcase vents, blowdown vents, pump seals or diaphragms, 

compressors, separators, pressure vessels, dehydrators, heaters, instruments, and meters) and 

provisions to repair or replace components or equipment if evidence of fugitive emissions is 

discovered during the OGI survey. All repairs must be made as soon as practicable, but no later 

than 15 calendar days after the OGI survey. In addition, all repairs must be re-surveyed 

immediately after repair using Method 21 instrument (using a repair threshold of 10,000 ppm) to 

ensure the fugitive emissions are no longer visible.

Control Effectiveness

Potential emission reduction percentages from the implementation of an OGI monitoring 

program varies from 40 to 99 percent.151 The data from these studies are based on the gathering 

of individual OGI surveys at various oil and natural gas industry segment sites. The variation in 

the percent reductions from these OGI surveys generally depended on whether large fugitive 

emission sources were found (e.g., open thief hatches, open dump valves, etc.) during the OGI 

survey and other assumptions made by the authors. However, these studies in the white paper did 

not provide information on the potential emission reductions from the implementation of an 

annual, semiannual, quarterly or monthly OGI monitoring and repair program. A report was 

found after the publication of the white paper from the Colorado Air Quality Control 

Commission152 estimated (1) 40 percent reduction for annual OGI monitoring for well 

production tank batteries with an uncontrolled VOC emissions of greater than 6 tpy or less than

 

151 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Leaks, Office of Air Quality Planning and 

Standards. Research Triangle Park, NC. April 2014. Available at

http://www.epa.gov/airquality/oilandgas/2014papers

152 Colorado Air Quality Control Commission, Initial Economic Impact Analysis for Proposed Revisions to 

Regulation Number 7 (5 CCR 1001-9). November 15, 2013.
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or equal to 12 tpy; (2) 60 percent reduction for quarterly OGI monitoring for well production 

tank batteries with an uncontrolled VOC emissions of greater than 12 tpy and less than or equal 

to 50 tpy; (3) 60 percent reduction for quarterly OGI monitoring for well production tank 

batteries with uncontrolled VOC emissions of greater than 12 tpy and less than or equal to 50 

tpy; and (4) 80 percent reduction for monthly OGI monitoring at well production tank batteries 

with uncontrolled VOC emissions greater than 50 tpy. 

From the review of the studies in the white paper and the Colorado Economic Impact 

Analysis, we expect the emission reductions from the implementation of an OGI monitoring and 

repair program to vary depending on the frequency of monitoring. For this analysis, we estimated 

emission reductions for the OGI monitoring frequency options (annual, semiannual and 

quarterly) using the estimated emission reductions from Colorado’s Economic Impact Analysis 

for conducting the OGI monitoring and repair program. Based on this range of expected 

emission reductions as characterized by Colorado’s Economic Impact Analysis, it is expected 

that an OGI monitoring program in combination with a repair program can reduce fugitive 

methane and VOC emissions from these segments by 40 percent on an annual frequency, 60 

percent on a semiannual frequency and 80 percent on a quarterly frequency as well as minimize 

the loss of salable gas. Tables 9-9, 9-10 and 9-11 summarize the estimated emission reductions 

for annual, semiannual and quarterly OGI monitoring for the oil and natural gas well site model 

plants and the gathering and boosting station model plant.

Cost Impacts

Costs (2012 dollars) for preparing and implementing a fugitive emission monitoring plan 

were estimated using hourly estimates for each of the plan elements. The costs are based on the 

following assumptions:

(1) Labor cost for each of the monitoring plan elements was estimated to be $57.80 per hour;

(2) Reading of the rule and instructions would take one person four hours to complete at a 

cost of $231.20;

(3) Development of a fugitive emission monitoring plan would take two and one half people

a total of 60 hours to complete at a cost of $3,468;

(4) Initial activities planning are estimated to take two people a total of 32 hours to complete 

at a cost of $1,849;
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(5) For companies that own and operate well sites, the cost of notification of compliance 

status was estimated to be $58 for 22 well sites for a total of $1,272 per company. For 

gathering and boosting stations the total notification cost was estimated to be $58; and

(6) Subsequent activities planning are estimated to take two people a total of 12 hours to 

complete at a cost of $1,387. For well sites, this cost was divided among the total number 

of well sites owned by a company, which was assumed to be 22. The cost per well site 

was estimated to be $63.

Costs for implementing a fugitive emission monitoring plan on a company level for well 

sites and a facility level for gathering and boosting stations were estimated for each of the 

monitoring and repair elements. The costs are based on the following assumptions:

Costs for implementing a fugitive emission monitoring plan on a company level for well 

sites and a facility level for gathering and boosting stations were estimated for each of the 

monitoring and repair elements. The costs are based on the following assumptions:

(1) The cost for OGI monitoring using an outside contractor was assumed to be $600 for a 

well site and $2,300 for a gathering and boosting station for each survey;

(2) Repair costs were estimated to be $299 for well sites and $3,436 for gathering and 

boosting stations per survey. These costs were estimated assuming that 1.18 percent of 

the components leak and 75 percent are repaired online and 25 percent are repaired 

offline;

(3) Cost for resurvey of components after offline repair based on $2.00 per component 

resurveyed. This is based on the assumption that a company purchases Method 21 

instrumentation (estimated to be $10,800153) and is able to perform the resurvey without 

needing contractors; and

(4) Preparation of annual reports was estimated to take one person a total of 4 hours to 

complete at a cost of $231.

The initial setup cost or capital costs for well sites was calculated by summing up the 

costs for reading the rule, development of fugitive emissions monitoring plan, initial activities 

planning, and notification of initial compliance status. The total capital costs of these activities 

was calculated to be $17,620 per company. Assuming that each company owns and operates 22 

 

153 Memorandum to Jodi Howard, EPA/OAQPS from Cindy Hancy, RTI International, Analysis of Emission 

Reduction Techniques for Equipment Leaks, December 21, 2011. EPA-HQ-OAR-2002-0037-0180
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well sites, the capital costs per well site was estimated to be $801. For gathering and boosting 

stations, the capital costs was estimated to be $16,407 per facility. 

For well sites and gathering and boosting stations, the annual costs include: subsequent 

activities planning, OGI camera survey by an outside contractor, cost of repair of fugitive 

emissions found, preparation and submittal of an annual report, storing and filing of records, and 

the amortized capital costs over eight years at seven percent discount rate. The annual costs for

annual, semiannual and quarterly OGI surveying (inclusive of contractor costs, cost of repair of 

fugitive emissions found, preparation and submittal of an annual report, and amortized capital 

costs over eight years at seven percent interest) were calculated for each of the industry

segments. Table 9-11, 9-12 and 9-13 present summaries of the cost of control for VOC for the 

three OGI monitoring frequency options (i.e., annual, semiannual and quarterly). The tables also 

provide a weighted average for the well sites, which include oil production and natural gas 

production well sites. The weighted averages were calculated using 2020 activity counts. The 

number of well sites were derived using information from the DrillingInfo database154 and 

assuming an annual growth rate of 6.45 percent, which was determined from National Energy

Modeling System (NEMS) data155. Using this data and the assumption of 2 well per well site, the 

2020 activity counts were determined to be 5,518 gas well sites and 16,562 oil well sites. These 

values were used to calculate a weighted average cost of control of oil production well sites and 

natural gas production well sites.

 

154 DrillingInfo is a private organization specializing in oil and gas data and statistical analysis. The DrillingInfo

database is focused on historical oil and gas production data and drilling permit data. The version used for this 

analysis was dated February 2014.

155 NEMS is a model of the U.S. energy economy developed and maintained by the EIA. NEMS is used to produce 

the Annual Energy Outlook (AEO), a reference publication that provides detailed forecasts of the energy economy 

from the current year to 2040.
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Table 9-11. Summary of the Model Plant VOC Cost of Control for the Annual OGI 

Monitoring Option

Model Plant

Annual 

VOC 

Emission 

Reductions

(tpy)a

Capital 

Costs

($2012)b

Annual Costs

($2012/year)c

Cost of Control

($2012/ton)

Without 

savings

With 

savings d

Without 

savings

With 

savings d

Natural Gas Well Site 0.50 $801 $1,329 $908 $2,633 $1,799

Oil Well Site 0.12 $801 $1,329 $1,228 $10,992 $10,158

Well Site Program Weighted 

Average e $8,903 $8,069

Gathering and Boosting 

Station 3.9 $16,407 $10,124 $6,865 $2,591 $1,757

a. Assumes 40% reduction with the implementation of annual OGI monitoring.

b. The capital costs for oil and natural gas well sites and gathering and boosting stations includes the cost of 

implementing the monitoring program which includes reading the rule, developing and implementing a monitoring 

plan (including initial activities planning), notification of initial compliance status, and purchase of a Method 21 

monitoring device.

c. Annual costs for oil and natural gas well sites and gathering and boosting stations include annual monitoring and repair costs 

and amortization of the capital costs over 8 years at 7% interest.

d. Recovery credits were calculated based on methane reductions, assuming methane is 82.9% of natural gas 

composition, and the value of the natural gas recovered as $4 Mcf. 

e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well sites and 

16,562 oil well sites.
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Table 9-12. Summary of the Model Plant VOC Cost of Control for the Semiannual OGI 

Monitoring Option

Model Plant

Annual VOC 

Emission 

Reductions

(tpy) a

Capital 

Costs

($2012)b

Annual Costs

($2012/year) c

Cost of Control

($2012/ton)

Without 

savings

With 

savings d

Without 

savings

With 

savings d

Natural Gas Well Site 0.76 $801 $2,230 $1,599 $2,945 $2,111

Oil Well Site 0.18 $801 $2,230 $2,079 $12,294 $11,460

Well Site Program

Weighted Average e $9,958 $9,124

Gathering and Boosting 

Station 5.85 $16,407 $15,881 $10,993 $2,710 $1,876

a. Assumes 60% reduction with the implementation of semiannual OGI monitoring.

b. The capital cost for oil and natural gas well sites and gathering and boosting stations includes the cost of 

implementing the monitoring program which includes reading the rule, developing and implementing a monitoring 

plan (including initial activities planning), notification of initial compliance status, and purchase of a Method 21 

monitoring device.

c. Annual costs for oil and natural gas well sites and gathering and boosting stations include semiannual monitoring and repair 

costs and amortization of the capital cost over 8 years at 7% interest.

d. Recovery credits were calculated based on methane reductions, assuming that methane is 82.9% of natural gas 

composition, and the value of the natural gas recovered as $4 Mcf. 

e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well sites and 16,562 oil well 

sites.
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Table 9-13. Summary of the Model Plant VOC Cost of Control for the Quarterly OGI 

Monitoring Option

Model Plant

Annual VOC 

Emission 

Reductions

(tpy) a

Capital 

Costs

($2012)b

Annual Costs

($2012/year) c

Cost of Control

($2012/ton)

Without 

savings

With 

savings d

Without 

savings

With 

savings d

Natural Gas Well Site 1.01 $801 $4,031 $3,190 $3,994 $3,160

Oil Well Site 0.24 $801 $4,031 $3,830 $16,669 $15,836

Well Site Program

Weighted Average e $13,502 $12,668

Gathering and Boosting 

Station 7.81 $16,407 $27,396 $20,879 $3,506 $2,672

a Assumes 80% reduction with the implementation of quarterly OGI monitoring.

b The capital costs for oil and natural gas well sites and gathering and boosting stations includes the cost of 

implementing the monitoring program which includes reading the rule, developing and implementing a monitoring 

plan (including initial activities planning), notification of initial compliance status, and purchase of a Method 21 

monitoring device.

c. Annual costs for oil and natural gas well sites and gathering and boosting stations include quarterly monitoring and repair costs 

and amortization of the capital costs over 8 years at 7% interest.

d Recovery credits were calculated assuming natural gas reductions based methane reductions, methane as 82.9% of 

natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well sites and 16,562 oil well 

sites.

9.3.1.2 Fugitive Emission Detection and Correction with Method 21

Description

Another option that can be used to reduce fugitive emissions from well sites and 

gathering and boosting stations involves the development of a fugitive emissions monitoring plan 

using Method 21 to detect leaks from equipment and components. The plan would incorporate 

surveying of equipment and components at a specified interval and repair threshold using a 

Method 21 instrument, which also includes operational requirements for the Method 21 

instrument, along with repair, recordkeeping and reporting requirements. A facility can use a 

corporate-wide fugitive emissions monitoring plan that covers the collection of fugitive emission 

components at well sites and gathering and boosting stations and a site specific fugitive 

emissions monitoring plan specific to each collection of fugitive emissions components at a well 

site or gathering and boosting station. Alternatively, a facility can use a site-specific plan for 

each collection of fugitive emissions components at a well-site or gathering and boosting station

that contains both the corporate-wide and site-specific plan elements. The plan would also 
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include provisions for repair or replacement of equipment or components if evidence of fugitive 

emissions are discovered during the survey. The monitoring plan would include inspection of all 

fugitive emission components and would require the repair where evidence of fugitive emissions 

is discovered (as soon as practicable, but generally no later than 15 calendar days after the 

Method 21 survey). In addition, all repairs would be re-surveyed immediately after repair to 

ensure the fugitive emissions are below the specified repair threshold.

Control Effectiveness

Potential control efficiencies for Method 21 monitoring were estimated to be 67 to 98 

percent depending on repair threshold and monitoring frequency in the 2015 NSPS proposal. The 

Method 21 control options included repair thresholds of 10,000, 2,500 and 500 parts per million 

(ppm) and annual, semiannual and quarterly monitoring frequencies. Tables 9-12, 9-13 and 9-14 

present the summaries of the estimated emission reductions for annual, semiannual and quarterly 

Method 21 monitoring for the three repair thresholds for the well site and the gathering and 

boosting station model plants.

Cost Impacts

Costs (2012 dollars) for preparing and implementing a fugitive emission monitoring plan 

were estimated using hourly estimates for each of the plan elements. The costs are based on the 

following assumptions:

(1) Labor cost for each of the monitoring plan elements was estimated to be $57.80 per hour;

(2) Reading of the rule and instructions would take one person four hours to complete at a 

cost of $231.20;

(3) Development of a fugitive emission monitoring plan would take two and one half people 

a total of 60 hours to complete at a cost of $3,468;

(4) Initial activities planning are estimated to take two people a total of 16 hours to complete 

at a cost of $1,849;

(5) For companies that own and operate well sites, the cost notification of compliance status 

was estimated to be $58 for 22 well sites for a total of $1,272 per company. For gathering 

and boosting stations the notification of compliance cost was estimated to be $58;

(6) The cost of purchasing a Method 21 monitoring device and data collection system was 

estimated to be $25,300 per company; and
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(7) Subsequent activities planning are estimated to take two people a total of 12 hours to 

complete at a cost of $1,387. For oil and natural gas well sites, this cost was divided 

among the total number of well sites owned by a company, which was assumed to be 22. 

The cost per well site was estimated to be $63. For gathering and boosting stations the 

subsequent activities planning was estimated to be $1,387.

Costs for implementing a fugitive emission monitoring plan on a company level for well 

sites and a facility level for gathering and boosting stations were estimated for each of the 

monitoring and repair elements. The costs are based on the following assumptions:

(1) Method 21 monitoring was estimated to take 2 people a total of 4 hours to survey a well 

production site at a cost of $462 per survey. For gathering and boosting stations, Method 

21 monitoring was estimated to take 2 people a total of 8 hours to survey the station at a 

cost of $925 per survey;

(2) Annual repair costs for well sites were estimated to be $2,999 using a repair threshold of 

10,000 ppm, $5,067 using a repair threshold of 2,500 ppm and $5,400 using a repair 

threshold of 500 ppm. These costs were estimated assuming that 7.49% of the 

components leak at 10,000 ppm, 12.25% of the components leak at 2,500 ppm and 

13.53% of the components leak at 500 ppm. The repair costs assume 75% are repaired 

online and 25% are repaired offline;

(3) Annual repair costs for gathering and boosting stations were estimated to be $29,288 

using a repair threshold of 10,000 ppm, $47,821 using a repair threshold of 2,500 ppm 

and $52,900 using a repair threshold of 500 ppm. These costs were estimated assuming 

that 7.49% of the components leak at 10,000 ppm, 12.25% of the components leak at 

2,500 ppm and 13.53% of the components leak at 500 ppm. The repair costs assume 75% 

are repaired online and 25% are repaired offline;

(4) Cost for resurvey of components after repair based on $2.00 per component resurveyed; 

and

(5) Preparation of annual reports was estimated to take 1 person a total of 4 hours to 

complete at a cost of $231.

The initial setup cost or capital costs for oil and natural gas well sites was calculated by 

summing up the costs for reading the rule, development of fugitive emissions monitoring plan, 

initial activities planning, acquisition of a Method 21 monitoring device and data collection 
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system and notification of initial compliance status. The total capital costs of these activities was 

estimated to be $32,120 per company. Assuming that each company owns and operates 22 well 

sites, the capital costs per well site was estimated to be $1,460. 

For gathering and boosting stations, the capital costs includes; reading the rule, 

development of fugitive emissions monitoring plan, initial activities planning, acquisition of a 

Method 21 monitoring device and data collection system and notification of initial compliance 

status. The total capital costs of these activities was estimated to be $30,907 per station. 

For oil and natural gas well sites, the annual costs include; subsequent activities planning, 

Method 21 survey, cost of repair of fugitive emissions found, preparation and submittal of an 

annual report, storing and filing of records, and the amortized capital costs over eight years at 

seven percent interest. The annual costs for annual, semiannual and quarterly Method 21 

surveying (inclusive of cost of repair of fugitive emissions found, preparation and submittal of an 

annual report, and amortized capital costs over eight years at seven percent interest) were 

calculated for each of the industry segments. Tables 9-14, 9-15 and 9-16 present summaries of 

the cost of control for VOC at each of the repair thresholds (i.e., 10,000, 2,500, and 500 ppm) for 

the three monitoring frequency options (i.e., annual, semiannual and quarterly). 
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Table 9-14. Summary of the Model Plant VOC Cost of Control for the Annual 

Method 21 Monitoring Option

Model Plant

Annual 

VOC 

Emission 

Reductions

(tpy) a

Capital 

Costs

($2012)b

Annual Costs

($2012/year) c

Cost of Control

($2012/ton)

Without 

savings

With 

savings d

Without 

savings

With 

savings d

10,000 ppm Repair Threshold

Natural Gas Well Site 1.03 $1,460 $4,020 $3,157 $3,885 $3,051

Oil Well Site 0.20 $1,460 $4,020 $3,813 $19,847 $18,826

Well Site Program Weighted 

Average e $15,858 $14,884

Gathering and Boosting 

Station 8.01 $30,907 $37,203 $30,523 $4,644 $3,810

2,500 ppm Repair Threshold

Natural Gas Well Site 1.19 $1,460 $6,103 $5,113 $5,145 $4,311

Oil Well Site 0.28 $1,460 $6,103 $5,866 $21,475 $20,642

Well Site Program Weighted 

Average e

$17,394 $16,560

Gathering and Boosting 

Station 9.18 $30,907 $55,860 $48,203 $6,083 $5,249

500 ppm Repair Threshold

Natural Gas Well Site 1.24 $1,460 $6,437 $5,406 $5,206 $4,372

Oil Well Site 0.30 $1,460 $6,437 $6,190 $21,728 $20,894

Well Site Program Weighted 

Average e $17,599 $16,765

Gathering and Boosting 

Station 9.57 $30,907 $60,973 $52,990 $6,369 $5,535

a. Assumes 84% reduction at 10,000 ppm repair threshold, 94% reduction at 2,500 ppm repair threshold and 98% 

reduction at 500 ppm repair threshold with the implementation of annual Method 21 monitoring.

b. The capital costs for oil and natural gas well sites and gathering and boosting stations includes the cost of 

implementing the monitoring program which includes reading the rule, developing and implementing a monitoring 

plan (including initial activities planning), notification of initial compliance status, and purchase of a Method 21 

monitoring device.

c. Annual costs for oil and natural gas well sites and gathering and boosting stations include annual monitoring and 

repair costs and amortization of the capital costs over 8 years at 7% interest.d. Recovery credits for oil and natural gas

well sites were calculated assuming natural gas reductions based methane reductions, methane as 82.9% of natural 

gas composition, and the value of the natural gas recovered as $4 Mcf. 

e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well sites and 16,562 oil well 

sites.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

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Table 9-15. Summary of the Model Plant VOC Cost of Control for the Semiannual 

Method 21 Monitoring Option

Model Plant

Annual 

VOC 

Emission 

Reductions

(tpy) a

Capital 

Costs

($2012)b

Annual Costs

($2012/year) c

Cost of Control

($2012/ton)

Without 

savings

With 

savings d

Without 

savings

With 

savings d

10,000 ppm Repair Threshold

Natural Gas Well Site 0.91 $1,460 $4,482 $3,725 $4,934 $4,100

Oil Well Site 0.22 $1,460 $4,482 $4,301 $20,593 $19,759

Well Site Program Weighted 

Average e $16,680 $15,846

Gathering and Boosting 

Station 7.03 $30,907 $38,128 $32,263 $5,421 $4,587

2,500 ppm Repair Threshold

Natural Gas Well Site 1.16 $1,460 $6,565 $5,597 $5,655 $4,821

Oil Well Site 0.28 $1,460 $6,565 $6,333 $23,605 $22,771

Well Site Program Weighted 

Average e $19,119 $18,285

Gathering amd Boosting 

Station 8.99 $30,907 $56,785 $49,291 $6,318 $5,485

500 ppm Repair Threshold

Natural Gas Well Site 1.22 $1,460 $6,899 $5,879 $5,637 $4,803

Oil Well Site 0.29 $1,460 $6,899 $6,655 $23,529 $22,695

Well Site Program Weighted 

Average e $19,058 $18,224

Gathering and Boosting 

Station 9.48 $30,907 $61,898 $53,996 $6,532 $5,698

a. Assumes 72% reduction at 10,000 ppm repair threshold, 92% reduction at 2,500 ppm repair threshold and 97% 

reduction at 500 ppm repair threshold with the implementation of annual Method 21 monitoring.

b. The capital costs for oil and natural gas well sites and gathering and boosting stations includes the cost of 

implementing the monitoring program which includes reading the rule, developing and implementing a monitoring 

plan (including initial activities planning), notification of initial compliance status, and purchase of a Method 21 

monitoring device.

c. Annual costs for oil and natural gas well sites and gathering and boosting stations include semiannual monitoring 

and repair costs and amortization of the capital costs over 8 years at 7% interest.

d. Recovery credits for oil and natural gas well sites were calculated assuming natural gas reductions based methane 

reductions, methane as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well sites and 16,562 oil well 

sites.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

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Table 9-16. Summary of the Model Plant VOC Cost of Control for the Quarterly

Method 21 Monitoring Option

Model Plant

Annual 

VOC 

Emission 

Reductions

(tpy) a

Capital 

Costs

($2012)b

Annual Costs

($2012/year) c

Cost of Control

($2012/ton)

Without 

savings

With 

savings d

Without 

savings

With 

savings d

10,000 ppm Repair Threshold

Natural Gas Well Site 0.85 $1,460 $5,407 $4,702 $6,396 $5,562

Oil Well Site 0.20 $1,460 $5,407 $5,238 $26,696 $25,862

Well Site Program

Weighted Average e $21,623 $20,789

Gathering and Boosting 

Station 6.55 $30,907 $39,978 $34,519 $6,108 $5,274

2,500 ppm Repair Threshold

Natural Gas Well Site 1.12 $1,460 $7,490 $6,553 $6,669 $5,835

Oil Well Site 0.27 $1,460 $7,490 $7,265 $27,838 $27,004

Well Site Program

Weighted Average e $22,548 $21,714

Gathering and Boosting 

Station 8.69 $30,907 $58,635 $51,385 $6,744 $5,910

500 ppm Repair Threshold

Natural Gas Well Site 1.19 $1,460 $7,824 $6,835 $6,597 $5,763

Oil Well Site 0.28 $1,460 $7,824 $7,587 $27,534 $26,700

Well Site Program

Weighted Average e $22,302 $21,468

Gathering and Boosting

Station 9.18 $30,907 $63,747 $56,090 $6,942 $6,108

a. Assumes 67% reduction at 10,000 ppm repair threshold, 89% reduction at 2,500 ppm repair threshold and 94% 

reduction at 500 ppm repair threshold with the implementation of annual Method 21 monitoring.

b. The capital costs for oil and natural gas well sites includes the cost of implementing the monitoring program of 

$32,120 divided by an average of 22 well sites per company. 

c. Annual costs for oil and natural gas well sites and gathering and boosting stations include semiannual monitoring 

and repair costs and amortization of the capital costs over 8 years at 7% interest.

d. Recovery credits for oil and natural gas well sites were calculated assuming natural gas reductions based methane 

reductions, methane as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well sites and 16,562 oil well 

sites.
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9.3.2 Existing Federal, State and Local Regulations

9.3.2.1 Federal Regulations that Specifically Require Control of VOC 

Emissions

For each well site and compressor station, the EPA is proposing NSPS requirements that 

would require the development of one or more fugitive emissions monitoring plans that includes 

semiannual monitoring by OGI and repair of leaking fugitive emission components. 

9.3.2.2 State and Local Regulations that Specifically Require Control of VOC 

Emissions

States may have permitting restrictions on VOC emissions that may apply to an emission

source as a result of an operating, NSR NA, or PSD permit (e.g., on a case-by-case basis) based 

on air quality maintenance or improvement goals of an area. Permits specify what construction is 

allowed, what emission limits must be met, and often how the source must be operated. To 

assure that sources follow the permit requirements, permits also contain monitoring, 

recordkeeping, and reporting requirements. Permits specify what construction is allowed, what 

emission limits must be met, and often how the source must be operated. To assure that sources 

follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting 

requirements. 

The State of Colorado has regulations that require annual leak inspections at all well 

sites, compressor stations upstream of the processing plant and storage vessels. These regulations 

allow OGI inspections, Method 21 or other “[d]ivision approved instrument based monitoring 

device or method” to detect leaks (Colorado Department of Public Health and Environment, Air 

Quality Control Commission, Regulation Number 7). 

The State of Wyoming, as part of its permitting guidance, requires facilities with VOC 

emissions greater than 4 tpy in the Upper Green River Basin, the Jonah-Pinedale Anticline 

Development Area and Normally Pressured Lance to conduct quarterly leak emissions 

inspections, and OGI inspections are allowed in addition to Method 21 inspections or audiovisual-olfactory inspections (Wyoming Department of Environmental Quality, Oil and Gas 

Production Facilities, Chapter 6, Section 2 Permitting Guidance, September 2013). 
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The State of Ohio requires operators to perform regular inspections to identify methane 

equipment leaks from horizontal wells and to repair leaks, where indicated. An owner or operator 

can either apply for a general or traditional emissions permit. The State of Ohio’s updated 

existing leak detection general permit requires more frequent monitoring through use of infrared 

cameras and portable sampling instruments. Initially, operators must conduct quarterly, rather 

than annual, leak monitoring. If minimal leaks are found, leak monitoring can be reduced to 

semiannual or annual inspections. If leaks are in excess of two percent, however, operators must 

continue quarterly monitoring. When leaks are identified, corrective action must be taken within 

five days (Ohio EPA General Permit Program; 

http://epa.ohio.gov/dapc/genpermit/genpermits.aspx#127854018-recently-issued-model-generalpermits). 

9.4 Recommended RACT Level of Control

Based on our evaluation of available data obtained in the development of the 2015 

proposed NSPS, peer review comments received on the equipment leaks white paper, and 

existing regulations that control VOC emissions from oil and natural gas production sites, we 

recommend that RACT for the collection of fugitive emission components at well sites with an 

average production of greater than 15 barrel equivalents and gathering and boosting stations be 

the implementation of a monitoring plan that includes semiannual monitoring using OGI and 

repair of components that are found to be leaking. 

As discussed in section 9.3.2.2 of this chapter, existing state and local regulations already 

require fugitive emissions monitoring of oil and natural gas production sites. The monitoring 

techniques listed in these requirements include the use of either Method 21 or OGI to locate 

fugitive emissions from equipment and components. In addition, peer review comments received 

on the equipment leaks white paper show that some companies are voluntarily monitoring their 

production sites using OGI to eliminate leaks from equipment. Monitoring and repair of 

equipment and components using OGI or Method 21 are the most viable methods for reducing 

fugitive emissions from equipment leaks in the production segment of the oil and natural gas

industry. 

Although both Wyoming and Ohio require quarterly monitoring of components at 

production sites and Pennsylvania has drafted a General Operating Permit that specifies quarterly 
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monitoring at a compressor station, we believe that quarterly monitoring could cause a burden on 

small businesses in the U.S. We believe that many operators would need to hire contractors due 

to the cost of the specialized equipment needed to perform the monitoring survey and the 

training necessary to properly operate the equipment whether OGI or Method 21 is used. In

addition, we believe that small businesses would be the most likely to hire such contractors 

because they are less likely to have excess capital to purchase monitoring equipment and train 

operators. There is some concern regarding the limited supply of qualified contractors to perform 

monitoring surveys which may lead to disadvantages for small businesses. Larger businesses, 

due to the economic clout they have by offering the contractors more work due to the higher 

number of wells they own, may preferentially retain the services of a large portion of the

available contractors. This could potentially result in small businesses experiencing a longer wait 

time to obtain contractor services. The monitoring plan recommendations would also cause the 

surveys to take more time, thus affecting the availability of OGI equipment and contractors. 

Therefore, if quarterly monitoring surveys are specified, the available supply of qualified 

contractors and OGI instruments may not be sufficient for small businesses to obtain timely

monitoring surveys. For these reasons, we recommend that semiannual monitoring at well sites 

and gathering and boosting compressor stations as RACT.

The VOC cost of control for semiannual monitoring using OGI was estimated to be 

$2,111 per ton of VOC reduced for natural gas well sites, $11,460 per ton of VOC reduced for 

oil well sites with a weighted average of $9,124 per ton of VOC reduced, and $1,876 per ton of 

VOC reduced for gathering and boosting stations considering natural gas savings. The cost of 

control for natural gas well sites and gathering and boosting stations is considered to be 

reasonable. For oil well sites, although the cost per ton of VOC reduced is higher than it is for 

natural gas wells sites and gathering and boosting stations, since publication of the “Oil and 

Natural Gas Sector Leaks”156 white paper, additional emissions data have become available, 

including reporting year 2013 data from GHGRP that confirm that fugitive emission sources are 

significant from oil and natural gas well sites and gathering and boosting stations. Notably, we 

further identified that many studies have shown a skewed distribution for emissions related to 

leaks, where a majority of emissions come from a minority of sources. Commenters on the white 

 

156 Available at http://www.epa.gov/airquality/oilandgas/2014papers/20140415leaks.pdf. 
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papers agreed that emissions from equipment leaks exhibit a skewed distribution, and pointed to 

other examples of data sets in which the majority of VOC emissions from leaks come from a 

minority of components. Commenters noted that emitters are likely due to random occurrences 

of low-probability but high-emissions conditions. Commenters also noted that in addition to 

variation in emissions per component, there can be significant variation in component counts and 

that these vary based on well production, site geography, type of gas, and company-determined 

processing equipment.

For well sites, the cost of control for a monitoring plan using Method 21 with a 10,000 

ppm leak detection is generally more costly than the use of OGI where there are a large number 

of equipment components to be monitored. The cost for a natural gas well site was estimated to 

be $3,051 per ton of VOC for annual monitoring and $4,100 per ton of VOC for semiannual 

monitoring considering natural gas savings. The cost for an oil well site was estimated to be 

$18,826 per ton of VOC for annual monitoring and $19,759 per ton of VOC for annual 

monitoring considering natural gas savings. As shown in section 9.3.1 of this chapter, the cost of 

control for the 2,500 ppm and 500 ppm repair threshold options are higher than the 10,000 ppm 

repair threshold option. The use of a monitoring plan using Method 21 with a 10,000 ppm leak 

detection may, however, be a lower cost alternative to OGI where there are fewer equipment 

components to be monitored. For gathering and boosting stations, the cost of control for a 

monitoring plan using Method 21 with a 10,000 ppm leak detection is estimated to be $4,587 per 

ton of VOC removed for semiannual monitoring and $3,810 for annual monitoring considering 

natural gas savings. 

In summary, we recommend the following RACT for the collection of fugitive emission 

components at oil and natural gas well sites and compressor stations in the production segment:

RACT for the Collection of Fugitive Emission Components at Oil and Natural Gas Well 

Sites with Wells that Produce, on Average, Greater than 15 Barrel Equivalents per Day

per Well and Compressor Stations in the Production Segment (Located from the 

Wellhead to the Point of Custody Transfer to the Natural Gas Transmission and Storage 

Segment or Oil Pipeline): We recommend the implementation of a monitoring plan that 

includes semiannual monitoring using OGI and repair of components that are found to be 

leaking at well sites and compressor stations. We also recommend that each fugitive 

emissions component repaired or replaced be resurveyed to ensure there is no leak after 
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repair by the use of either Method 21 or OGI no later than 15 days of finding fugitive 

emissions.

9.5 Factors to Consider in Developing Fugitive Emissions RACT 

Procedures 

To ensure that fugitive emissions are properly monitored and repaired (as necessary) 

under the RACT recommendations, we suggest that regulatory agencies specify OGI monitoring 

and equipment repair recordkeeping and reporting requirements to document compliance. 

9.5.1 Monitoring Recommendations

We recommend that regulatory agencies require a fugitive emissions OGI monitoring 

plan that covers fugitive emission component sources that includes basic required monitoring 

plan elements. We recommend that regulatory agencies require both a corporate-wide and a sitespecific fugitive emissions OGI monitoring plan that covers the collection of fugitive emissions 

components at well sites and compressor stations. Alternatively, regulatory agencies may decide 

to require a single OGI monitoring site-specific plan for each collection of fugitive emissions 

components at a well site and each collection of fugitive emissions components at a compressor

station that covers the elements of both the corporate-wide and site-specific plans. 

We suggest that the corporate-wide monitoring plan include the following minimum 

elements:

(1) Frequency for conducting surveys;

(2) Technique for determining fugitive emissions;

(3) Manufacturer and model number of fugitive emissions detection equipment to be used;

(4) Procedures and timeframes for identifying and repairing fugitive emissions components 

from which fugitive emissions are detected, including timeframes for fugitive emission 

components that are unsafe to repair;

(5) Procedures and timeframes for verifying fugitive emission component repairs;

(6) Records that will be kept and the length of time records will be kept;

(7) Verification that your optical gas imaging equipment meets the specification 

requirements;

(8) Procedure for a daily verification check;
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Fugitive Emissions

(9) Procedure for determining the operator’s maximum viewing distance from the equipment 

and how the operator will ensure that this distance is maintained;

(10) Procedure for determining maximum wind speed during which monitoring can be

performed and how the operator will ensure monitoring occurs only at wind speeds below 

this threshold;

(11) Procedures for conducting surveys;

(12) Training and experience needed prior to performing surveys; and

(13) Procedures for calibration and maintenance.

(14) Procedures should comply with those recommended by the manufacturer.

We suggest that you require the following minimum elements for the site-specific 

monitoring plan:

(1) Deviations from your corporate-wide plan;

(2) Sitemap; and

(3) Defined walking path (to ensure that all fugitive emissions components are within sight 

of the path and accounts for interferences).

We recommend a monitoring survey of each collection of fugitive emissions components 

at a well site and collection of fugitive emissions components at a compressor station be 

conducted at least semiannually after the initial survey and that consecutive semiannual 

monitoring surveys be conducted at least four months apart. We recommend that the monitoring 

frequency be increased to quarterly in the event that two consecutive semiannual monitoring 

surveys detect fugitive emissions at 1.0 percent or more of the fugitive emissions components at 

a well site or at 1.0 percent or more of the fugitive emissions components at a compressor

station. We also recommend that the monitoring frequency be decreased to annual in the event 

that two consecutive semiannual surveys detect fugitive emissions at less than 1.0 percent of the 

fugitive emissions components at a well site, or at less than 1.0 percent of the fugitive emissions 

components at a compressor station. We also recommend that you require that the monitoring 

frequency return to semiannual if an annual survey detects fugitive emissions between one and 

three percent of the fugitive emissions components at the well site, or between one and three 

percent of the fugitive emissions components at the compressor station, and return to quarterly if 

a survey detects fugitive emissions at greater than three percent of the fugitive emissions 
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Fugitive Emissions

components at the well site, or greater than three percent of the fugitive emissions components at 

the compressor station.

9.5.2 Repair Recommendations

We recommend that regulatory agencies require that any identified source of fugitive 

emissions be repaired or replaced as soon as practicable, but no later than 15 calendar days after 

detection of the fugitive emissions. If the repair or replacement is technically infeasible or unsafe 

to repair during operation of the unit, the repair or replacement must be completed during the 

next scheduled shutdown or within 6 months, whichever is earlier. We also recommend that 

repaired or replaced fugitive emission components be required to be resurveyed as soon as 

practicable, but no later than 15 days after completion of the repair or replacement, to ensure that 

there is no leak. For repairs that cannot be made during the monitoring survey when the fugitive 

emissions are initially found, we recommend that regulatory agencies require that the operator 

resurvey the repaired fugitive emissions components using either Method 21 or OGI no later than

15 days of finding such fugitive emissions. A fugitive emissions component is repaired when 

either the Method 21 instrument indicates a concentration of less than 500 ppm above 

background, or an OGI instrument shows no indication of visible emissions.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: ii

We include modular rule language in this appendix for our recommended RACT for oil 

and natural gas industry sources. The intent of this language is to provide regulation language 

that states can easily adapt for use. Although we include model rule language for closed vent 

systems, control devices and performance tests (that apply across several model rule 

requirements for sources), it is acknowledged that states may have existing similar language in 

their programs that they may want to use in lieu of the model language provided. 

The model rule language does not specify rule effective dates or compliance dates. These

dates will be determined by the state or local government regulatory authority. State and local 

government agencies are encouraged to search this model rule language for places where the 

“regulatory authority” will need to specify dates (e.g., effective date, compliance date) by 

searching for (“regulatory authority”) in the model rule language.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: iii

Appendix: Table of Contents

A Storage Vessels: VOC Emission Control Requirements............................................................... A-1

A.1 Applicability.................................................................................................................. A-1

A.2 What VOC Emission Control Requirements Apply to Storage Vessels? ..................... A-1

A.3 Initial Compliance Demonstration Requirements......................................................... A-3

A.4 Continuous Compliance Demonstration Requirements................................................ A-4

A.5 Recordkeeping and Reporting Requirements................................................................ A-8

A.6 Definitions................................................................................................................... A-10

B Pneumatic Controllers: VOC Emission Control Requirements..................................................... B-1

B.1 Applicability.................................................................................................................. B-1

B.2 What VOC Emission Control Requirements Apply to Pneumatic Controllers?........... B-1

B.3 Initial Compliance Demonstration Requirements......................................................... B-2

B.4 Continuous Compliance Demonstration Requirements................................................ B-3

B.5 Recordkeeping and Reporting Requirements................................................................ B-4

B.6 Definitions..................................................................................................................... B-5

C Compressors: VOC Emissions Control Requirements.................................................................. C-1

C.1 Applicability.................................................................................................................. C-1

C.2 What VOC Emission Control Requirements Apply to Centrifugal Compressors?....... C-1

C.3 What VOC Emission Control Requirements Apply to Reciprocating Compressors? .. C-2

C.4 Initial Compliance Demonstration Requirements......................................................... C-3

C.5 Continuous Compliance Demonstration Requirements................................................ C-5

C.6 Recordkeeping and Reporting Requirements................................................................ C-9

C.7 Definitions................................................................................................................... C-11

D Cover and Closed Vent System Requirements.............................................................................. D-1

D.1 What Are My Cover and Closed Vent System Requirements?..................................... D-1

D.2 What Are My Initial and Continuous Cover and Closed Vent System Inspection and 

Monitoring Requirements?............................................................................................ D-3

E VOC Emission Control Device Requirements ...............................................................................E-1

E.1 Initial Control Device Compliance Requirements .........................................................E-1

E.2 Continuous Control Device Monitoring Requirements..................................................E-5

F Performance Test Procedures .........................................................................................................F-1

G Equipment Component VOC Leaks at Natural Gas Processing Plants......................................... G-1
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Appendix: iv

G.1 Applicability.................................................................................................................. G-1

G.2 What VOC Emission Control Requirements Apply to Equipment Components at an 

Onshore Natural Gas Processing Plant?........................................................................ G-1

G.3 What Exceptions to the Equipment Leak VOC Emission Control Requirements Apply at 

Onshore Natural Gas Processing Plants? ...................................................................... G-2

G.4 How Do I Demonstrate Initial and Continued Compliance with the VOC Emission 

Control Requirements for Equipment Components Subject to Control Requirements at 

Onshore Natural Gas Processing Plants? ...................................................................... G-4

G.5 Equipment Component VOC Emission Control Requirements.................................... G-4

G.5.1 VOC Emission Control Requirements: General.................................................... G-4

G.5.2 What Equipment Component VOC Emission Control Requirements that Apply to 

Pumps in Light Liquid Service? ............................................................................ G-7

G.5.3 What are the Equipment Component VOC Emission Control Requirements that 

Apply to Compressors?........................................................................................ G-11

G.5.4 What Equipment Component VOC Emission Control Requirements Apply to 

Pressure Relief Devices in Gas/Vapor Service? .................................................. G-13

G.9.5 What Equipment Component VOC Emission Control Requirements Apply to 

Sampling Connection Systems?........................................................................... G-14

G.5.6 What Equipment Component VOC Emission Control Requirements Apply to OpenEnded Valves or Lines? ....................................................................................... G-15

G.5.7 What Equipment Component VOC Emission Control Requirements Apply to 

Valves in Gas/Vapor Service and in Light Liquid Service? ................................ G-16

G.5.8 What Equipment Component VOC Emission Control Requirements Apply to 

Pumps, Valves, and Connectors in Heavy Liquid Service and Pressure Relief 

Devices in Light Liquid or Heavy Liquid Service? ............................................. G-19

G.5.9 What Delay of Repair of Equipment Components Requirements Apply When 

Equipment Component Leaks Have Been Detected? .......................................... G-19

G.5.10 What VOC Emission Control Requirements Apply for Closed Vent Systems and 

Control Devices?.................................................................................................. G-21

G.5.11 What VOC Emission Control Requirements Apply to Connectors in Gas/Vapor 

Service and in Light Liquid Service?................................................................... G-24

G.6 Alternative Standards.................................................................................................. G-28

G.6.1 Alternative Standards for Valves—Allowable Percentage of Valves Leaking ... G-28

G.6.2 Alternative Standards for Valves—Skip Period Leak Detection and Repair ...... G-29

G.7 Equipment Leak Test Methods and Procedures.......................................................... G-30

G.8 Recordkeeping and Reporting Requirements.............................................................. G-35

G.9 Definitions................................................................................................................... G-44
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Appendix: v

H Pneumatic Pumps: VOC Emissions Control Requirements .......................................................... H-1

H.1 Applicability.................................................................................................................. H-1

H.2 What VOC Emission Reduction Requirements Apply to Natural Gas-Driven Pneumatic 

Pumps? .......................................................................................................................... H-1

H.3 Initial Compliance Demonstration Requirements......................................................... H-3

H.4 Continuous Compliance Demonstration Requirements................................................ H-4

H.5 Recordkeeping and Reporting Requirements................................................................ H-7

H.6 Definitions..................................................................................................................... H-9

I Fugitive Emissions Components VOC Emissions Control Requirements......................................I-1

I.1 Applicability....................................................................................................................I-1

I.2 What VOC Emission Control Requirements Apply to the Collection of Fugitive 

Emission Components at a Well Site and a Compressor Station? ..................................I-1

I.3 Initial Compliance Demonstration ..................................................................................I-5

I.4 Continuous Compliance Demonstration .........................................................................I-5

I.5 Recordkeeping and Reporting Requirements..................................................................I-6

I.6 Definitions.......................................................................................................................I-7
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: A-1

A Storage Vessels: VOC Emission Control Requirements

A.1 Applicability

(a) The VOC emissions control requirements of section A apply to each storage vessel 

located in the oil and natural gas industry (excluding distribution) that has the potential for VOC 

emissions equal to or greater than 6 tpy. The potential for VOC emissions must be calculated 

using a generally accepted model or calculation methodology, based on the maximum average 

daily throughput determined for a 30-day period of production prior to the applicable emission 

determination deadline established by your regulatory authority. The determination may take into 

account requirements under a legally and practically enforceable limit in an operating permit or 

other requirement established under a federal, state, local or tribal authority. Any vapor from the 

storage vessel that is recovered and routed to a process through a VRU designed and operated as 

specified in this section is not required to be included in the determination of VOC potential to 

emit for purposes of determining applicability, provided you comply with the requirements in 

section A.2.

(b) The storage vessel VOC emission control requirements specified in this section do not 

apply to storage vessels subject to and controlled in accordance with the requirements for storage 

vessels in 40 CFR part 60, subpart Kb, 40 CFR part 63, subparts G, CC, HH, or WW.

A.2 What VOC Emission Control Requirements Apply to Storage Vessels?

For each storage vessel, you must comply with the VOC emissions control requirements 

of paragraphs (a) through (e) in this section by the compliance date established by your 

regulatory authority. Requirements for storage vessels removed from service are presented in 

paragraph (f) of this section.

(a) You must reduce VOC emissions from each storage vessel by 95 percent.

(b) (1) Except as required in paragraph (b)(2) of this section, if you use a control device 

to reduce emissions, you must equip the storage vessel with a cover that meets the requirement 
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Appendix: A-2

of section D.1(a), that is connected through a closed vent system that meets the requirements of 

section D.1(b) and routed to a control device that meets the conditions specified in paragraph 

(b)(3)(i) and (ii) of this section. As an alternative to routing the closed vent system to a control 

device, you may route the closed vent system to a process.

(2) If you use a floating roof to reduce emissions, you must meet the requirements of 40 

CFR 60.112b(a)(1) or (2) and the relevant monitoring, inspection, recordkeeping, and reporting 

requirements in 40 CFR part 60, subpart Kb.

(3) (i) For each control device used to meet the VOC emission reduction control 

requirements in paragraph (a), you must comply with the applicable control device compliance 

requirements of section E.1(d) and install and operate a continuous parameter monitoring system 

for each control device as specified in section E.2(c) through (f), except as provided for in 

section E.2(b).

(ii) You must operate each control device used to comply with this rule at all times when 

gases, vapors, and fumes are vented from your storage vessel through a closed vent system to a 

control device. You may vent more than one source to a control device.

(c) You must demonstrate initial compliance with the VOC emission reduction 

requirements that apply to each storage vessel as required in section A.3.

(d) You must demonstrate continuous compliance with the VOC emission control

requirements that apply to each storage vessel as required by section A.4.

(e) You must perform the required recordkeeping and reporting as required by section 

A.5.

(f) Requirements for storage vessels that are removed from service or returned to service.

If you are the owner or operator of a storage vessel subject to the VOC emission control 

requirements that is removed from service, you must comply with paragraphs (f)(1) through (3)

of this section. A storage vessel is not an affected source under this section for the period that it 

is removed from service.
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Appendix: A-3

(1) For a storage vessel to be removed from service, you must comply with the 

requirements of paragraph (f)(1)(i) and (ii) of this section.

(i) You must completely empty and degas the storage vessel, such that the storage vessel 

no longer contains crude oil, condensate, produced water or intermediate hydrocarbon liquids. A 

storage vessel where liquid is left on walls, as bottom clingage or in pools due to floor 

irregularity is considered to be completely empty.

(ii) You must submit a notification in your next annual report, identifying all storage 

vessels removed from service during the reporting period and the date of its removal from 

service.

(2) If the storage vessel subject to VOC emission control requirements identified in 

paragraph (f)(1) of this section is returned to service during the reporting year, you must comply 

with paragraphs (f)(3) of this section.

(3) You must submit a notification in your next annual report identifying each storage 

vessel that has been returned to service and the date of its return to service.

A.3 Initial Compliance Demonstration Requirements

You must demonstrate initial compliance by the compliance date specified by your 

regulatory authority by demonstrating compliance with the VOC emission control requirements 

for each storage vessel complying with section A.2 by complying with the requirements in 

paragraphs (a) through (g) of this section. 

(a) You determine the potential VOC emission rate as specified in section A.1(a).

(b) You reduce VOC emissions from each storage vessel subject to VOC emission 

control requirements by 95 percent or greater as required in section A.2 and as demonstrated by 

section F.

(c) If you use a control device to reduce emissions, you equip your storage vessel with a 

cover that meets the requirements of section D.1(a) that is connected through a closed vent 

system that meets the requirements of section D.1(b) and is routed to a control device that meets 
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Appendix: A-4

the requirements of section E.1. As an alternative to routing the closed vent system to a control 

device, you may route the closed vent system to a process. 

(d) You conduct an initial performance test as required in section F within 180 days after 

the effective date of this rule, as established by your regulatory authority. 

(e) You conduct the initial cover and closed vent system inspections required in section 

D.2 within 180 days after the effective date of this rule as established by your regulatory

authority.

(f) You submit the initial annual report for your storage vessels as required in section 

A.5(b).

(g) You maintain the records as specified in section A.5(a).

A.4 Continuous Compliance Demonstration Requirements

You have demonstrated continuous compliance for each storage vessel subject to the 

VOC emission control requirements in section A.2 by meeting the requirements in paragraphs (a) 

through (c) of this section.

(a) For each storage vessel subject to VOC emission reduction requirements, you must 

demonstrate continuous compliance according to paragraphs (b) and (c) of this section.

(b) You must reduce VOC emissions from the storage vessel by 95 percent or greater.

(c) For each control device used to reduce emissions, you must demonstrate continuous 

compliance with the performance requirements of section A.2(a) using the procedures specified 

in paragraphs (c)(1) through (7) of this section, as applicable. If you use a condenser as the 

control device to achieve the requirements specified in section A.2(a), you demonstrate 

compliance according to paragraph (c)(8) of this section. You may switch between compliance 

with paragraphs (c)(1) through (7) of this section and compliance with paragraph (c)(8) of this 

section only after at least 1 year of operation in compliance with the selected approach. You 
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: A-5

must provide notification of such a change in the compliance method in the next annual report, 

as required in section A.5(b), following the change. 

(1) You must operate below (or above) the site specific maximum (or minimum) 

parameter value established according to the requirements of section E.2(f)(1).

(2) You must calculate the daily average of the applicable monitored parameter in 

accordance with section E.2(e) except that the inlet gas flow rate to the control device must not 

be averaged.

(3) Compliance with the operating parameter limit is achieved when the daily average of 

the monitoring parameter value calculated under paragraph (c)(2) of this section is either equal to 

or greater than the minimum monitoring value or equal to or less than the maximum monitoring 

value established under paragraph (c)(1) of this section. When performance testing of a 

combustion control device is conducted by the device manufacturer as specified in section F(d), 

compliance with the operating parameter limit is achieved when the criteria in section F(e) are 

met.

(4) You must operate the continuous monitoring system required in section E.2(a) at all 

times the source is operating, except for periods of monitoring system malfunctions, repairs 

associated with monitoring system malfunctions, and required monitoring system quality 

assurance or quality control activities (including, as applicable, system accuracy audits and 

required zero and span adjustments). A monitoring system malfunction is any sudden, 

infrequent, not reasonably preventable failure of the monitoring system to provide valid data. 

Monitoring system failures that are caused in part by poor maintenance or careless operation are 

not malfunctions. You are required to complete monitoring system repairs in response to 

monitoring system malfunctions and to return the monitoring system to operation as 

expeditiously as practicable.

(5) You may not use data recorded during monitoring system malfunctions, repairs 

associated with monitoring system malfunctions, or required monitoring system quality 

assurance or control activities in calculations used to report emissions or operating levels. You 
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Appendix: A-6

must use all the data collected during all other required data collection periods to assess the 

operation of the control device and associated control system.

(6) Failure to collect required data is a deviation of the monitoring requirements, except 

for periods of monitoring system malfunctions, repairs associated with monitoring system 

malfunctions, and required quality monitoring system quality assurance or quality control 

activities (including, as applicable, system accuracy audits and required zero and span 

adjustments).

(7) If you use a combustion control device to meet the requirements of section A.2(a) and 

you demonstrate compliance using the test procedures specified in section F(b), you must 

comply with paragraphs (c)(7)(i) through (iv) of this section.

(i) A pilot flame must be present at all times of operation.

(ii) Devices must be operated with no visible emissions, except for periods not to exceed 

a total of one minute during any 15 minute period. A visible emissions test using section 11 of 

Method 22, 40 CFR part 60, appendix A, must be performed at least once every calendar month, 

separated by at least 15 days between each test. The observation period shall be 15 minutes. 

(iii) Devices failing the visible emissions test must follow manufacturer's repair 

instructions, if available, or best combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair 

and maintenance activities for each unit must be recorded in a maintenance and repair log and 

must be available for inspection.

(iv) Following return to operation from maintenance or repair activity, each device must 

pass a Method 22, 40 CFR part 60, appendix A, visual observation as described in paragraph 

(c)(2)(vii)(B) of this section.

(8) If you use a condenser as the control device to achieve the percent reduction 

performance requirements specified in section A.2(a), you must demonstrate compliance using 

the procedures in paragraphs (c)(8)(i) through (v) of this section.
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Appendix: A-7

(i) You must establish a site-specific condenser performance curve according to section 

E.2(f)(2).

(ii) You must calculate the daily average condenser outlet temperature in accordance with 

section E.2(e).

(iii) You must determine the condenser efficiency for the current operating day using the 

daily average condenser outlet temperature calculated under paragraph (c)(8)(ii) of this section 

and the condenser performance curve established under paragraph (c)(8)(i) of this section.

(iv) You must calculate the 365-day rolling average TOC emission reduction, as 

appropriate, from the condenser efficiencies as determined in paragraph (c)(8)(iii) of this section.

(A) If you have less than 120 days of data for determining average TOC emission 

reduction, you must calculate the average TOC emission reduction for the first 120 days of 

operation. You have demonstrated compliance with the overall 95 percent reduction requirement 

if the 120-day average TOC emission reduction is equal to or greater than 95 percent.

(B) After 120 days and no more than 364 days of operation, you must calculate the 

average TOC emission reduction as the TOC emission reduction averaged over the number of 

days of operation where you have data. You have demonstrated compliance with the overall 95

percent reduction requirement, if the average TOC emission reduction is equal to or greater than 

95 percent.

(v) If you have data for 365 days or more of operation, you have demonstrated 

compliance with the TOC emission reduction if the rolling 365-day average TOC emission 

reduction calculated in paragraph (c)(8)(4) of this section is equal to or greater than 95 percent.

(d) You must submit the annual report required by section A.5(b) and maintain the 

records as specified in section A.5(a).
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Appendix: A-8

A.5 Recordkeeping and Reporting Requirements

(a) Recordkeeping requirements. For each storage vessel, you must maintain the records 

identified in paragraphs (a)(1) through (11) of this section, as applicable, either onsite or at the 

nearest local field office for at least five years.

(1) If required to reduce emissions by complying with section A.2(a), the records 

specified in paragraphs (a)(6) through (8) of this section and section D.2, as applicable.

(2) Records of each VOC emissions determination for each storage vessel made under 

A.1(a) including identification of the model or calculation methodology used to calculate the 

VOC emission rate.

(3) Records of deviations in cases where the storage vessel was not operated in 

compliance with the requirements specified in sections A.2, D, E and F, as applicable.

(4) For storage vessels that are skid-mounted or permanently attached to something that 

is mobile (such as trucks, railcars, barges or ships), records indicating the number of consecutive 

days that the vessel is located at a site in the oil and natural gas production segment, natural gas 

processing segment or natural gas transmission and storage segment. If a storage vessel is 

removed from a site and, within 30 days, is either returned to or replaced by another storage 

vessel at the site to serve the same or similar function, then the entire period since the original 

storage vessel was first located at the site, including the days when the storage vessel was 

removed, must be added to the count towards the number of consecutive days.

(5) Records of the identification and location of each storage vessel subject to emission 

control requirements.

(6) Records of each closed vent system inspection required under section D.2(a) and (b).

(7) A record of each cover inspection required under section D.2(c).
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Appendix: A-9

(8) If you are subject to the bypass requirements of section D.2(d), a record of each 

inspection or a record each time the key is checked out or a record of each time the alarm is 

sounded.

(9) For each carbon adsorber installed on a storage vessel, records of the schedule for 

carbon replacement (as determined by the design analysis requirements of section E.1(a)(2)) and 

records of each carbon replacement as specified in section E.1(c)(1).

(10) For each storage vessel subject to the control device requirements of section E.2(c) 

and (d), records of the inspections, including any corrective actions taken, the manufacturers' 

operating instructions, procedures and maintenance schedule as specified in section E.2(h). 

Records of section 11, EPA Method 22, 40 CFR part 60, appendix A results, which include: 

company, location, company representative (name of the person performing the observation), sky 

conditions, process unit (type of control device), clock start time, observation period duration (in 

minutes and seconds), accumulated emission time (in minutes and seconds), and clock end time. 

You may create your own form including the above information or use Figure 22-1 in EPA 

Method 22, 40 CFR part 60, appendix A. Control device manufacturer operating instructions, 

procedures and maintenance schedule must be available for inspection.

(11) A log of records for all inspection, repair and maintenance activities for each control 

device failing the visible emissions test as specified in section A.4(c)(7(iii).

(b) Reporting requirements. For storage vessels, you must submit annual reports 

containing the information specified in paragraphs (b)(1) through (6) of this section.

(1) An identification, including the location, of each storage vessel subject to VOC 

emission control requirements. The location of the storage vessel shall be in latitude and 

longitude coordinates in decimal degrees to an accuracy and precision of five (5) decimals of a 

degree using the North American Datum of 1983.

(2) Documentation of the VOC emission rate determination according to section A.1(a).
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Appendix: A-10

(3) Records of deviations specified in paragraph (a)(3) of this section that occurred 

during the reporting period.

(4) A statement that you have met the requirements specified in section A.3(b) and (c). 

(5) You must identify each storage vessel that is removed from service during the 

reporting period as specified in section A.2(f)(1), including the date the storage vessel was 

removed from service.

(6) You must identify each storage vessel returned to service during the reporting period 

as specified in section A.2(f)(3), including the date the storage vessel was returned to service..

A.6 Definitions

Condensate means hydrocarbon liquid separated from natural gas that condenses due to 

changes in the temperature, pressure, or both, and remains liquid at standard conditions.

Gas processing plant process unit means equipment assembled for the extraction of 

natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or 

other operations associated with the processing of natural gas products. A process unit can 

operate independently if supplied with sufficient feed or raw materials and sufficient storage 

facilities for the products.

Natural gas processing plant (gas plant) means any processing site engaged in the 

extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to 

natural gas products, or both. A Joule-Thompson valve, a dew point depression valve, or an 

isolated or standalone Joule-Thompson skid is not a natural gas processing plant.

Natural gas transmission means the pipelines used for the long distance transport of 

natural gas (excluding processing). Specific equipment used in natural gas transmission includes 

the land, mains, valves, meters, boosters, regulators, storage vessels, dehydrators, compressors, 

and their driving units and appurtenances, and equipment used for transporting gas from a 

production plant, delivery point of purchased gas, gathering system, storage area, or other 

wholesale source of gas to one or more distribution area(s).
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Appendix: A-11

Pressure vessel means a storage vessel that is used to store liquids or gases and is 

designed not to vent to the atmosphere as a result of compression of the vapor headspace in the 

pressure vessel during filling of the pressure vessel to its design capacity.

Produced water means water that is extracted from the earth from an oil or natural gas

well, or that is separated from crude oil, condensate, or natural gas after extraction.

Removed from service means that a storage vessel subject to the VOC control 

requirements has been physically isolated and disconnected from the process for a purpose other 

than maintenance.

Returned to service means that a storage vessel subject to the VOC requirements that was 

removed from service has been:

(1) Reconnected to the original source of liquids or has been used to replace any storage 

vessel subject to the VOC requirements; or

(2) Installed in any location covered by this rule and introduced with crude oil,

condensate, intermediate hydrocarbon liquids or produced water. 

Routed to a process or route to a process means the emissions are conveyed via a closed 

vent system to any enclosed portion of a process where the emissions are predominantly recycled 

and/or consumed in the same manner as a material that fulfills the same function in the process 

and/or transformed by chemical reaction into materials that are not regulated materials and/or 

incorporated into a product; and/or recovered. Salable quality gas means natural gas that meets 

the flow line or collection system operator specifications, regardless of whether such gas is sold.

Storage vessel means a tank or other vessel that contains an accumulation of crude oil, 

condensate, intermediate hydrocarbon liquids, or produced water, and that is constructed 

primarily of nonearthen materials (such as wood, concrete, steel, fiberglass, or plastic) which 

provide structural support. A well completion vessel that receives recovered liquids from a well 

after startup of production following flowback for a period which exceeds 60 days is considered 

a storage vessel under this rule. A tank or other vessel shall not be considered a storage vessel if 

it has been removed from service in accordance with the requirements of (f)(2) of this section 
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Appendix: A-12

until such time as such tank or other vessel has been returned to service. For the purposes of this 

rule, the following are not considered storage vessels:

(1) Vessels that are skid-mounted or permanently attached to something that is mobile 

(such as trucks, railcars, barges or ships), and are intended to be located at a site for less than 180 

consecutive days. If you do not keep or are not able to produce records, as required by section 

A.5(a)(4), showing that the vessel has been located at a site for less than 180 consecutive days, 

the vessel described herein is considered to be a storage vessel from the date the original vessel 

was first located at the site. This exclusion does not apply to a well completion vessel as 

described above.

(2) Process vessels such as surge control vessels, bottoms receivers or knockout vessels.

(3) Pressure vessels designed to operate in excess of 204.9 kilopascals and without 

emissions to the atmosphere.

Underground storage vessel means a storage vessel stored below ground.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: B-1

B Pneumatic Controllers: VOC Emission Control Requirements

B.1 Applicability 

The VOC emission control requirements specified in section B.2 apply to the pneumatic 

controllers specified in paragraphs (a) and (b) of this section.

(a) For natural gas processing plants, each pneumatic controller, which is a single 

continuous bleed natural gas-driven pneumatic controller.

(b) For each pneumatic controller located from the wellhead to the natural gas processing 

plant or point of custody transfer to an oil pipeline, which is a single continuous bleed natural 

gas-driven pneumatic controller operating at a natural gas bleed rate greater than 6 standard 

cubic feet per hour.

B.2 What VOC Emission Control Requirements Apply to Pneumatic 

Controllers?

For each pneumatic controller, you must comply with requirements based on natural gas 

as a surrogate for VOC, as specified in either paragraph (b)(1) or (c)(1) of this section, as 

applicable. Pneumatic controllers meeting the conditions in paragraph (a) of this section are 

exempt from these requirements.

(a) The requirements of paragraph (b)(1) or (c)(1) of this section are not required if you 

determine that the use of a pneumatic controller with a bleed rate greater than 6 standard cubic 

feet per hour is required based on functional needs, including but not limited to response time, 

safety and positive actuation. However, you must tag such pneumatic controller with the date 

that the pneumatic controller is required to comply with the model rule (as established by your 

regulatory authority) that allows traceability to the records for that pneumatic controller, as 

required in section B.5(a)(2).

(b)(1) Each pneumatic controller subject to VOC emissions control requirements at a 

natural gas processing plant must have a bleed rate of zero.
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Appendix: B-2

(2) Each pneumatic controller subject to VOC emissions control requirements at a natural 

gas processing plant must be tagged with the date that the pneumatic controller is required to 

comply with the model rule (as established by your regulatory authority) that allows traceability

to the records for that pneumatic controller as required in section B.5(a)(4)

(c)(1) Each pneumatic controller subject to VOC emissions control requirements at a 

location between the wellhead and a natural gas processing plant or the point of custody transfer 

to an oil pipeline must have a bleed rate less than or equal to 6 standard cubic feet per hour.

(2) Each pneumatic controller subject to VOC emission control requirements at a location 

between the wellhead and a natural gas processing plant or the point of custody transfer to an oil 

pipeline must be tagged with the date that the pneumatic controller is required to comply with the 

model rule (as established by your regulatory authority) that allows traceability to the records for 

that controller as required in section B.5(a)(3).

(d) You must demonstrate initial compliance by the compliance date specified by your 

regulatory authority by demonstrating compliance with the VOC emission reduction 

requirements that apply to pneumatic controllers as required by section B.3.

(e) You must demonstrate continuous compliance with VOC emission reduction 

requirements that apply to pneumatic controllers as required by section B.4.

(f) You must perform the required recordkeeping and reporting as required by section 

B.5.

B.3 Initial Compliance Demonstration Requirements

You must demonstrate initial compliance with the VOC emission control requirements 

for your pneumatic controller by complying with the requirements specified in paragraphs (a) 

through (f) of this section by the compliance date specified by your regulatory authority, as 

applicable.
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Appendix: B-3

(a) You must demonstrate initial compliance by maintaining records as specified in 

section B.5(a)(2) of your determination that the use of a pneumatic controller with a bleed rate 

greater than 6 standard cubic feet of gas per hour is required as specified in section B.2(a).

(b) You own or operate a pneumatic controller located at a natural gas processing plant 

and your pneumatic controller is driven by a gas other than natural gas and therefore emits zero 

natural gas.

(c) You own or operate a pneumatic controller located between the wellhead and a 

natural gas processing plant and the manufacturer's design specifications indicate that the 

controller emits less than or equal to 6 standard cubic feet of gas per hour.

(d) You must tag each pneumatic controller according to the requirements of section 

B.2(b)(2) or (c)(2).

(e) You must include the information in paragraph (a) of this section and a listing of the 

pneumatic controller sources specified in paragraphs (b) and (c) of this section in the initial 

annual report according to the requirements of section B.5(b)

(f) You must maintain the records as specified in section B.5(a) for each pneumatic 

controller subject to VOC emission control requirements.

B.4 Continuous Compliance Demonstration Requirements

For each pneumatic controller, you must demonstrate continuous compliance according 

to paragraphs (a) through (c) of this section.

(a) You must continuously operate each pneumatic controller as required in section 

B.2(a), (b), or (c).

(b) You must submit the annual report as required in section B.5(b).

(c) You must maintain records as required in section B.5(a).
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Appendix: B-4

B.5 Recordkeeping and Reporting Requirements

(a) Recordkeeping requirements. For each pneumatic controller, you must maintain the 

records identified in paragraphs (a)(1) through (5) of this section onsite or at the nearest local 

field office for at least five years.

(1) Records of the date, location and manufacturer specifications for each pneumatic 

controller.

(2) If applicable, a record of the demonstration that the use of a pneumatic controller with 

a natural gas bleed rate greater than 6 standard cubic feet per hour is required and the reasons 

why.

(3) If the pneumatic controller is not located at a natural gas processing plant, records of 

the manufacturer's specifications indicating that the controller is designed such that natural gas 

bleed rate is less than or equal to 6 standard cubic feet per hour.

(4) If the pneumatic controller is located at a natural gas processing plant, records of the 

documentation that the natural gas bleed rate is zero.

(5) Records of deviations in cases where the pneumatic controller was not operated in 

compliance with the requirements specified in section B.2.

(b) Reporting requirements. You must submit annual reports containing the information 

specified in paragraphs (b)(1) through (3) of this section.

(1) An identification of each existing pneumatic controller and each pneumatic controller 

constructed, modified or reconstructed during the reporting period, including the identification 

information specified in section B.2(b)(2) or (c)(2).

(2) If applicable, documentation that the use of a pneumatic controller with a natural gas 

bleed rate greater than 6 standard cubic feet per hour is required and the reasons why.
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Appendix: B-5

(3) Records of deviations specified in paragraph (a)(5) of this section that occurred 

during the reporting period.

B.6 Definitions

Bleed rate means the rate in standard cubic feet per hour at which natural gas is 

continuously vented (bleeds) from a pneumatic controller.

Continuous bleed means a continuous flow of pneumatic supply natural gas to the 

process control device (e.g., level control, temperature control, pressure control) where the 

supply gas pressure is modulated by the process condition, and then flows to the valve controller 

where the signal is compared with the process set-point to adjust gas pressure in the valve 

actuator.

Intermittent/snap-action pneumatic controller means a pneumatic controller that vents 

non-continuously.

Natural gas-driven pneumatic controller means a pneumatic controller powered by

pressurized natural gas.

Natural gas processing plant (gas plant) means any processing site engaged in the 

extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to 

natural gas products, or both. A Joule-Thompson valve, a dew depression valve, or a standalone 

Joule-Thompson skid is not a natural gas processing plant.

Non-natural gas-driven pneumatic controller means an instrument that is actuated using 

other sources of power than pressurized natural gas; examples include solar, electric, and 

instrument air.

Pneumatic controller means an automated instrument used for maintaining a process 

condition such as liquid level, pressure, delta-pressure and temperature.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: C-1

C Compressors: VOC Emissions Control Requirements

C.1 Applicability

(a) Centrifugal compressors. Each centrifugal compressor, which is a single centrifugal 

compressor using wet seals located between the wellhead and point of custody transfer to the 

natural gas transmission and storage segment. A centrifugal compressor located at a well site, or 

an adjacent well site and servicing more than one well site, is not a source subject to VOC 

requirements under this rule.

(b) Reciprocating compressors. Each reciprocating compressor located between the 

wellhead and point of custody transfer to the natural gas transmission and storage segment. A 

reciprocating compressor located at a well site, or an adjacent well site and servicing more than 

one well site, is not a source subject to VOC requirements under this rule.

C.2 What VOC Emission Control Requirements Apply to Centrifugal 

Compressors?

For each centrifugal compressor, you must comply with the VOC emissions control 

requirements in paragraphs (a) through (g).

(a) You must reduce VOC emissions from each centrifugal compressor wet seal fluid 

degassing system by 95.0 percent or greater.

(b) If you use a control device to reduce emissions, you must equip the wet seal fluid 

degassing system with a cover that meets the requirements of section D.1(a). The cover must be 

connected through a closed vent system that meets the requirements of section D.1(b) and the 

closed vent system must be routed to a control device that meets the conditions specified in 

paragraph (c) of this section. As an alternative to routing the closed vent system to a control 

device, you may route the closed vent system to a process. 
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Appendix: C-2

(c) For each control device used to comply with the VOC emission reduction control 

requirements in paragraph (a), you must install and operate a continuous parameter monitoring 

system for each control device as specified in section E.2(a) through (f), except as provided for 

in section E.2(b).

(d) You must operate each control device installed on your centrifugal compressor in 

accordance with the requirements specified in paragraphs (d)(1) and (2) of this section.

(1) You must operate each control device used to comply with this rule at all times when 

gases, vapors, and fumes are vented from the wet seal fluid degassing system through the closed 

vent system to the control device. You may vent more than one source to a single control device.

(2) For each control device monitored in accordance with the requirements of section 

E.2(a) through (f), you must demonstrate continuous compliance according to the requirements 

of section C.5(a)(2), as applicable.

(e) You must demonstrate initial compliance with the VOC emission reduction 

requirements that apply to each centrifugal compressor as required by section C.4(a).

(f) You must demonstrate continuous compliance with the VOC emission control

requirements that apply to each centrifugal compressor as required by section C.5(a).

(g) You must perform the required recordkeeping and reporting as required by section 

C.6(a)(1) and (b)(1), as applicable.

C.3 What VOC Emission Control Requirements Apply to Reciprocating 

Compressors?

You must comply with the VOC emission control requirements in paragraphs (a) through 

(d) of this section for each reciprocating compressor.

(a) You must replace the reciprocating compressor rod packing according to either 

paragraph (a)(1) or (2) of this section or you must comply with paragraph (a)(3) of this section.
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Appendix: C-3

(1) Before the compressor has operated for 26,000 hours. The number of hours of 

operation must be continuously monitored beginning on the compliance date for your 

reciprocating compressor as specified by your regulatory authority, or the date of the most recent 

reciprocating compressor rod packing replacement, whichever is later.

(2) Prior to 36 months from the date of the most recent rod packing replacement, or 36 

months from the compliance date for a reciprocating compressor for which the rod packing has 

not yet been replaced.

(3) Collect the VOC emissions from the rod packing using a rod packing emissions 

collection system which operates under negative pressure and route the rod packing emissions to 

a process through a closed vent system that meets the requirements of section D.1(b).

(b) You must demonstrate initial compliance with requirements that apply to 

reciprocating compressor sources as required by section C.4(b).

(c) You must demonstrate continuous compliance with requirements that apply to 

reciprocating compressor sources as required by section C.5(b).

(d) You must perform the required recordkeeping and reporting as required by section 

C.6(a)(2) and (b)(2).

C.4 Initial Compliance Demonstration Requirements

You must demonstrate initial compliance by the compliance date specified by your 

regulatory authority by demonstrating compliance with the VOC emission control requirements 

for each centrifugal compressor by complying with the requirements in paragraph (a) of this 

section, and for each reciprocating compressor by complying with the requirements in paragraph 

(b) of this section. 

(a) Centrifugal compressors. You have achieved initial compliance with the VOC 

emission control requirements for each centrifugal compressor if you have complied with 

paragraphs (a)(1) through (6) of this section.
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Appendix: C-4

(1) You reduce VOC emissions from each centrifugal compressor wet seal fluid 

degassing system by 95 percent or greater as required in section C.2 and as demonstrated by

section F.

(2) You use a control device to reduce emissions, and you equip the wet seal fluid 

degassing system with a cover that meet the requirements of section D.1(a) that is connected 

through a closed vent system that meets the requirements of section D.1(b) and is routed to a 

control device that meets the requirements of section E.1. As an alternative to routing the closed 

vent system to a control device, you may route the closed vent system to a process.

(3) You conduct an initial performance test as required in section F within 180 days after 

the effective date specified by your regulatory authority.

(4) You conduct the initial cover and closed vent system inspections required in section 

D.2 within 180 days after the effective date specified by your regulatory authority.

(5) You submit the initial annual report for your centrifugal compressor as required in 

section C.6(b)(1).

(6) You maintain the records as specified in section C.6(a)(1)

(b) Reciprocating compressors. You have achieved initial compliance with the VOC 

emission control requirements for each reciprocating compressor if you have complied with 

paragraphs (b)(1) through (4) of this section.

(1) If complying with section C.3(a)(1) and (2), you must continuously monitored the 

number of hours of operation or tracked the number of months since the last rod packing 

replacement, beginning on the compliance date specified by your regulatory authority.

(2) If complying with section C.3(a)(3), you must operate the rod packing emissions 

collection system under negative pressure and route emissions to a process through a closed vent 

system that meets the requirements of section D.1(b) by the compliance date specified by your 

regulatory authority.
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Appendix: C-5

(3) You must submit the initial annual report for your reciprocating compressor as 

required in section C.6(b)(2).

(4) You maintain the records as specified in section C.6(a)(2).

C.5 Continuous Compliance Demonstration Requirements

You have demonstrated continuous compliance for each centrifugal compressor by

complying with the requirements of paragraph (a), and for each reciprocating compressor by

complying with the requirements of paragraph (b).

(a) Centrifugal compressors. For each centrifugal compressor subject to VOC emission 

reduction requirements, you must demonstrate continuous compliance according to paragraphs 

(a)(1) through (3) of this section.

(1) You must reduce VOC emissions from the wet seal fluid degassing system by 95.0 

percent or greater.

(2) For each control device used to reduce emissions, you must demonstrate continuous 

compliance with the performance requirements of section C.2(a) using the procedures specified 

in paragraphs (a)(2)(i) through (vii) of this section. If you use a condenser as the control device 

to achieve the requirements specified in section C.2(a), you must demonstrate compliance 

according to paragraph (a)(2)(viii) of this section. You may switch between compliance with 

paragraphs (a)(2)(i) through (vii) of this section and compliance with paragraph (a)(2)(viii) of 

this section only after at least 1 year of operation in compliance with the selected approach. You

must provide notification of such a change in the compliance method in the next annual report, 

as required in section C.6(b), following the change.

(i) You must operate below (or above) the site specific maximum (or minimum) 

parameter value established according to the requirements of section E.2(f)(1).

(ii) You must calculate the daily average of the applicable monitored parameter in 

accordance with section E.2(e) except that the inlet gas flow rate to the control device must not 

be averaged.
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Appendix: C-6

(iii) Compliance with the operating parameter limit is achieved when the daily average of 

the monitoring parameter value calculated under paragraph (a)(2)(ii) of this section is either 

equal to or greater than the minimum monitoring value or equal to or less than the maximum 

monitoring value established under paragraph (a)(2)(i) of this section. When performance testing 

of a combustion control device is conducted by the device manufacturer as specified in section 

F(d), compliance with the operating parameter limit is achieved when the criteria in section F(e) 

are met.

(iv) You must operate the continuous monitoring system required in section E.2(a) at all 

times the source is operating, except for periods of monitoring system malfunctions, repairs 

associated with monitoring system malfunctions, and required monitoring system quality 

assurance or quality control activities (including, as applicable, system accuracy audits and 

required zero and span adjustments). A monitoring system malfunction is any sudden, 

infrequent, not reasonably preventable failure of the monitoring system to provide valid data. 

Monitoring system failures that are caused in part by poor maintenance or careless operation are 

not malfunctions. You are required to complete monitoring system repairs in response to 

monitoring system malfunctions and to return the monitoring system to operation as 

expeditiously as practicable.

(v) You may not use data recorded during monitoring system malfunctions, repairs 

associated with monitoring system malfunctions, or required monitoring system quality 

assurance or control activities in calculations used to report emissions or operating levels. You 

must use all the data collected during all other required data collection periods to assess the 

operation of the control device and associated control system.

(vi) Failure to collect required data is a deviation of the monitoring requirements, except 

for periods of monitoring system malfunctions, repairs associated with monitoring system 

malfunctions, and required quality monitoring system quality assurance or quality control 

activities (including, as applicable, system accuracy audits and required zero and span 

adjustments).
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Appendix: C-7

(vii) If you use a combustion control device to meet the requirements of section C.2(a) 

and you demonstrate compliance using the test procedures specified in section F(b), you must 

comply with paragraphs (a)(2)(vii)(A) through (D) of this section.

(A) A pilot flame must be present at all times of operation.

(B) Devices must be operated with no visible emissions, except for periods not to exceed 

a total of one minute during any 15-minute period. A visible emissions test using section 11 of 

Method 22, 40 CFR part 60, appendix A, must be performed at least once every calendar month, 

separated by at least 15 days between each test. The observation period shall be 15 minutes. 

(C) Devices failing the visible emissions test must follow manufacturer's repair 

instructions, if available, or best combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair 

and maintenance activities for each unit must be recorded in a maintenance and repair log and 

must be available for inspection.

(D) Following return to operation from maintenance or repair activity, each device must 

pass a Method 22, 40 CFR part 60, appendix A, visual observation as described in paragraph 

(a)(2)(vii)(B) of this section.

(viii) If you use a condenser as the control device to achieve the percent reduction 

performance requirements specified in section C.2(a)(1), you must demonstrate compliance 

using the procedures in paragraphs (a)(2)(viii)(A) through (E) of this section.

(A) You must establish a site-specific condenser performance curve according to section 

E.2(f)(2).

(B) You must calculate the daily average condenser outlet temperature in accordance 

with section E.2(e).

(C) You must determine the condenser efficiency for the current operating day using the 

daily average condenser outlet temperature calculated under paragraph (a)(2)(viii)(B) of this
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Appendix: C-8

section and the condenser performance curve established under paragraph (a)(2)(viii)(A) of this 

section.

(D) You must calculate the 365-day rolling average TOC emission reduction, as 

appropriate, from the condenser efficiencies as determined in paragraph (a)(2)(viii)(C) of this 

section.

(1) If you have less than 120 days of data for determining average TOC emission 

reduction, you must calculate the average TOC emission reduction for the first 120 days of 

operation. You have demonstrated compliance with the overall 95.0 percent reduction 

requirement if the 120-day average TOC emission reduction is equal to or greater than 95.0 

percent.

(2) After 120 days and no more than 364 days of operation, you must calculate the 

average TOC emission reduction as the TOC emission reduction averaged over the number of 

days of operation where you have data. You have demonstrated compliance with the overall 95.0 

percent reduction requirement, if the average TOC emission reduction is equal to or greater than 

95.0 percent.

(E) If you have data for 365 days or more of operation, you have demonstrated 

compliance with the TOC emission reduction if the rolling 365-day average TOC emission 

reduction calculated in paragraph (a)(2)(viii)(D) of this section is equal to or greater than 95.0 

percent.

(3) You must submit the annual report required by section C.6(b)(1) and maintain the 

records as specified in section C.6(a)(1).

(b) Reciprocating compressors. For each reciprocating compressor subject to VOC 

emission reduction requirements, you must demonstrate continuous compliance according to 

paragraphs (b)(1) through (4) of this section.

(1) You must continuously monitor the number of hours of operation for each 

reciprocating compressor or track the number of months or the date of the most recent 
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: C-9

reciprocating compressor rod packing replacement, whichever is later, beginning on the 

compliance date.

(2) You must submit the annual report as required in section C.6(b)(2) and maintain 

records as required in section C.6(a)(2).

(3) You must replace the reciprocating compressor rod packing before the total number 

of hours of operation reaches 26,000 hours or the number of months since the most recent rod 

packing replacement reaches 36 months.

(4) If you comply with this rule by collecting and routing VOC emissions from the rod 

packing using a rod packing emissions collection system which operates under negative pressure 

as required by section C.3(a)(3), you must operate the rod packing emissions collection system 

under negative pressure and route emissions to a process through a closed vent system that meets 

the requirements of section D.1(b).

C.6 Recordkeeping and Reporting Requirements

(a) Recordkeeping requirements. 

(1) Centrifugal compressors. For each centrifugal compressor, you must maintain records 

of the information specified in paragraphs (a)(1)(i) and (ii) of this section, and, if required to 

comply with section C.2(a), the records specified in paragraphs (a)(1)(iii) through (ix) of this 

section. These records must be maintained onsite or at the nearest local field office for at least 

five years.

(i) An identification of each existing centrifugal compressor using a wet seal system and 

each centrifugal compressor constructed, modified or reconstructed during the reporting period.

(ii) Records of deviations where the centrifugal compressor was not operated in 

compliance with requirements specified in section C.2.

(iii) Records of each closed vent system inspection required under section D.2(a) and (b).
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Appendix: C-10

(iv) A record of each cover inspection required under section D.2(c).

(v) If you are subject to the bypass requirements of section D.2(d), a record of each 

inspection or a record each time the key is checked out or a record of each time the alarm is 

sounded.

(vi) If you are subject to the closed vent system no detectable emissions requirements of 

section D.2(a) and (b), a record of the monitoring in accordance with section D.2(e).

(vii) For each centrifugal compressor, records of the schedule for carbon replacement (as 

determined by the design analysis requirements of section F(c)(2) or (3)) and records of each 

carbon replacement as specified in section E.1(c)(1).

(viii) For each centrifugal compressor subject to the control device requirements of 

section X.E.1, records of minimum and maximum operating parameter values, continuous 

parameter monitoring system data, calculated averages of continuous parameter monitoring 

system data, results of all compliance calculations, and results of all inspections.

(ix) A log of records for all inspection, repair and maintenance activities for each control 

device failing the visible emissions test as specified in section C.5(a)(2)(vii)(C).

(2) Reciprocating compressors. For each reciprocating compressor VOC emissions 

source, you must maintain the records in paragraphs (a)(2)(i) through (iii) of this section.

(i) Records of the cumulative number of hours of operation or number of months since 

the previous replacement of the reciprocating compressor rod packing, or date of installation of a 

rod packing emissions collection system and closed vent system as specified in section 

C.3(a)(3)..

(ii) Records of the date and time of each reciprocating compressor rod packing 

replacement.

(iii) Records of deviations in cases where the reciprocating compressor was not operated 

in compliance with the requirements specified in section C.3.
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Appendix: C-11

(b) Reporting requirements. 

(1) Centrifugal compressors. For each centrifugal compressor, you must submit annual 

reports containing the information specified in paragraphs (b)(1)(i) through (iii) of this section.

(i) An identification of each existing centrifugal compressor using a wet seal system and 

each centrifugal compressor constructed, modified or reconstructed during the reporting period.

(ii) Records of deviations specified in paragraph (a)(1)(ii) of this section that occurred 

during the reporting period.

(iii) If required to comply with section C.2(a), the records specified in paragraphs 

(a)(1)(iii) through (viii) of this section.

(2) Reciprocating compressors. For each reciprocating compressor, you must submit 

annual reports containing the information specified in paragraphs (b)(2)(i) and (ii) of this section.

(i) The cumulative number of hours of operation or the number of months since the 

compliance date, or since the previous reciprocating compressor rod packing replacement, 

whichever is later.

(ii) Records of deviations specified in paragraph (a)(2)(iii) of this section that occurred 

during the reporting period.

C.7 Definitions

Centrifugal compressor means any machine for raising the pressure of a natural gas by

drawing in low pressure natural gas and discharging significantly higher pressure natural gas by 

means of mechanical rotating vanes or impellers. Screw, sliding vane, and liquid ring 

compressors are not centrifugal compressors for the purposes of this rule.

Compressor station means any permanent combination of one or more compressors that 

move natural gas at increased pressure from fields, in transmission pipelines, or into storage.
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Appendix: C-12

Reciprocating compressor means a piece of equipment that increases the pressure of a 

process gas by positive displacement, employing linear movement of the driveshaft.

Reciprocating compressor rod packing means a series of flexible rings in machined metal 

cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount 

of compressed natural gas that escapes to the atmosphere.

Routed to a process or route to a process means the emissions are conveyed via a closed 

vent system to any enclosed portion of a process where the emissions are predominantly recycled 

and/or consumed in the same manner as a material that fulfills the same function in the process 

and/or transformed by chemical reaction into materials that are not regulated materials and/or 

incorporated into a product; and/or recovered. Salable quality gas means natural gas that meets 

the flow line or collection system operator specifications, regardless of whether such gas is sold.
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Appendix: D-1

D Cover and Closed Vent System Requirements

D.1 What Are My Cover and Closed Vent System Requirements? 

You must meet the applicable requirements of this section for each cover and closed vent 

system where VOC emissions are routed to a control device or to a process.

(a) Cover requirements. (1) The cover and all openings on the cover (e.g., access hatches, 

sampling ports, pressure relief valves and gauge wells) shall form a continuous impermeable 

barrier over the entire surface area of the liquid in the storage vessel or wet seal fluid degassing 

system.

(2) Each cover opening shall be secured in a closed, sealed position (e.g., covered by a 

gasketed lid or cap) whenever material is in the unit on which the cover is installed except during 

those times when it is necessary to use an opening as follows:

(i) To add material to, or remove material from the unit (this includes openings necessary

to equalize or balance the internal pressure of the unit following changes in the level of the 

material in the unit);

(ii) To inspect or sample the material in the unit;

(iii) To inspect, maintain, repair, or replace equipment located inside the unit; or

(iv) To vent liquids, gases, or fumes from the unit through a closed-vent system, designed 

and operated in accordance with the requirements of paragraph (b)(1) of this section to a control 

device or to a process.

(3) Additional cover requirement for storage vessels. Each storage vessel thief hatch shall 

be equipped, maintained and operated with a weighted mechanism or equivalent, to ensure that 

the lid remains properly seated. You must select gasket material for the hatch based on 

composition of the fluid in the storage vessel and weather conditions.
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Appendix: D-2

(b) Closed vent system requirements. For closed vent system requirements using a control 

device or routing emissions to a process, you must comply with the following:

(1) You must design the closed vent system to route all gases, vapors, and fumes emitted 

from the VOC emissions source to a control device that meets the requirements specified in 

section E.1(a) and (c), or to a process.

(2) You must design and operate a closed vent system with no detectable emissions, as 

determined using olfactory, visual and auditory inspections. Each closed vent system that routes 

emissions to a process must be operational 95 percent of the year or greater.

(3) You must meet the requirements specified in paragraph (b)(3)(i) of this section if the 

closed vent system contains one or more bypass devices that could be used to divert all or a 

portion of the gases, vapors, or fumes from entering the control device or to a process.

(i) Except as provided in paragraph (b)(3)(ii) of this section, you must comply with either 

paragraph (b)(3)(i)(A) or (B) of this section for each bypass device.

(A) You must properly install, calibrate, maintain, and operate a flow indicator at the 

inlet to the bypass device that could divert the stream away from the control device or process to 

the atmosphere. Set the flow indicator to trigger an audible alarm, and initiate notification via 

remote alarm to the nearest field office, when the bypass device is open such that the stream is 

being, or could be, diverted away from the control device or process to the atmosphere.

(B) You must secure the bypass device valve installed at the inlet to the bypass device in 

the non-diverting position using a car-seal or a lock-and-key type configuration.

(ii) Low leg drains, high point bleeds, analyzer vents, open-ended valves or lines, and 

safety devices are not subject to the requirements of paragraph (b)(3)(i) of this section.
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Appendix: D-3

D.2 What Are My Initial and Continuous Cover and Closed Vent System 

Inspection and Monitoring Requirements?

Except as provided in paragraphs (e)(11) and (12) of this section, you must inspect each 

closed vent system according to the procedures and schedule specified in paragraphs (a) and (b) 

of this section, inspect each cover according to the procedures and schedule specified in 

paragraph (c) of this section, and inspect each bypass device according to the procedures of 

paragraph (d) of this section.

(a) For each closed vent system joint, seam, or other connection that is permanently or 

semi-permanently sealed (e.g., a welded joint between two sections of hard piping or a bolted 

and gasketed ducting flange), you must meet the requirements specified in paragraphs (a)(1) and 

(2) of this section.

(1) Conduct an initial inspection according to the test methods and procedures specified 

in paragraph (e) of this section to demonstrate that the closed vent system operates with no 

detectable emissions. You must maintain records of the inspection results.

(2) Conduct annual visual inspections for defects that could result in air emissions. 

Defects include, but are not limited to, visible cracks, holes, or gaps in piping; loose connections; 

liquid leaks; or broken or missing caps or other closure devices. You must monitor a component 

or connection using the test methods and procedures in paragraph (b) of this section to 

demonstrate that it operates with no detectable emissions following any time the component is 

repaired or replaced or the connection is unsealed. You must maintain records of the inspection 

results.

(b) For closed vent system components other than those specified in paragraph (a) of this 

section, you must meet the requirements of paragraphs (b)(1) through (3) of this section.

(1) Conduct an initial inspection according to the test methods and procedures specified 

in paragraph (e) of this section to demonstrate that the closed vent system operates with no 

detectable emissions by the date specified by your regulatory authority. You must maintain 

records of the inspection results.
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Appendix: D-4

(2) Conduct annual inspections according to the test methods and procedures specified in 

paragraph (e) of this section to demonstrate that the components or connections operate with no 

detectable emissions. You must maintain records of the inspection results.

(3) Conduct annual visual inspections for defects that could result in air emissions. 

Defects include, but are not limited to, visible cracks, holes, or gaps in ductwork; loose 

connections; liquid leaks; or broken or missing caps or other closure devices. You must maintain 

records of the inspection results.

(c) For each cover, you must meet the requirements in paragraphs (c)(1) and (2) of this 

section.

(1) Conduct visual inspections for defects that could result in air emissions. Defects 

include, but are not limited to, visible cracks, holes, or gaps in the cover, or between the cover 

and the separator wall; broken, cracked, or otherwise damaged seals or gaskets on closure 

devices; and broken or missing hatches, access covers, caps, or other closure devices. In the case 

where the storage vessel is buried partially or entirely underground, you must inspect only those 

portions of the cover that extend to or above the ground surface, and those connections that are 

on such portions of the cover (e.g., fill ports, access hatches, gauge wells, etc.) and can be 

opened to the atmosphere.

(2) You must initially conduct the inspections specified in paragraph (c)(1) of this section 

following the installation of the cover. Thereafter, you must perform the inspection at least once 

every calendar year, except as provided in paragraphs (e)(11) and (12) of this section. You must 

maintain records of the inspection results.

(d) For each bypass device, except as provided for in section D.1, you must meet the 

requirements of paragraphs (d)(1) or (2) of this section.

(1) Set the flow indicator to take a reading at least once every 15 minutes at the inlet to 

the bypass device that could divert the steam away from the control device to the atmosphere.
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Appendix: D-5

(2) If the bypass device valve installed at the inlet to the bypass device is secured in the 

non-diverting position using a car-seal or a lock-and-key type configuration, visually inspect the 

seal or closure mechanism at least once every month to verify that the valve is maintained in the 

non-diverting position and the vent stream is not diverted through the bypass device. You must 

maintain records of the inspections.

(e) No detectable emissions test methods and procedures. If you are required to conduct 

an inspection of a closed vent system or cover as specified in paragraphs (a), (b), or (c) of this 

section, you must meet the requirements of paragraphs (e)(1) through (13) of this section.

(1) You must conduct the no detectable emissions test procedure in accordance with 

Method 21, 40 CFR part 60, appendix A-7.

(2) The detection instrument must meet the performance criteria of Method 21, 40 CFR 

part 60, appendix A-7, except that the instrument response factor criteria in section 3.1.2(a) of 

Method 21 must be for the average composition of the fluid and not for each individual organic 

compound in the stream.

(3) You must calibrate the detection instrument before use on each day of its use by the 

procedures specified in Method 21, 40 CFR part 60, appendix A-7.

(4) Calibration gases must be as specified in paragraphs (e)(4)(i) and (ii) of this section.

(i) Zero air (less than 10 parts per million by volume hydrocarbon in air).

(ii) A mixture of methane in air at a concentration less than 10,000 parts per million by

volume.

(5) You may choose to adjust or not adjust the detection instrument readings to account 

for the background organic concentration level. If you choose to adjust the instrument readings 

for the background level, you must determine the background level value according to the 

procedures in Method 21, 40 CFR part 60, appendix A-7.
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Appendix: D-6

(6) Your detection instrument must meet the performance criteria specified in paragraphs 

(e)(6)(i) and (ii) of this section.

(i) Except as provided in paragraph (e)(6)(ii) of this section, the detection instrument 

must meet the performance criteria of Method 21, 40 CFR part 60, appendix A-7, except the 

instrument response factor criteria in section 3.1.2(a) of Method 21 must be for the average 

composition of the process fluid, not each individual volatile organic compound in the stream. 

For process streams that contain nitrogen, air, or other inerts that are not volatile organic 

compounds, you must calculate the average stream response factor on an inert-free basis.

(ii) If no instrument is available that will meet the performance criteria specified in 

paragraph (e)(6)(i) of this section, you may adjust the instrument readings by multiplying by the 

average response factor of the process fluid, calculated on an inert-free basis, as described in 

paragraph (e)(6)(i) of this section.

(7) You must determine if a potential leak interface operates with no detectable emissions 

using the applicable procedure specified in paragraph (e)(7)(i) or (ii) of this section.

(i) If you choose not to adjust the detection instrument readings for the background 

organic concentration level, then you must directly compare the maximum organic concentration 

value measured by the detection instrument to the applicable value for the potential leak interface 

as specified in paragraph (e)(8) of this section.

(ii) If you choose to adjust the detection instrument readings for the background organic 

concentration level, you must compare the value of the arithmetic difference between the 

maximum organic concentration value measured by the instrument and the background organic 

concentration value as determined in paragraph (e)(5) of this section with the applicable value 

for the potential leak interface as specified in paragraph (e)(8) of this section.

(8) A potential leak interface is determined to operate with no detectable organic 

emissions if the organic concentration value determined in paragraph (e)(7) of this section is less 

than 500 parts per million by volume.
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Appendix: D-7

(9) Repairs. In the event that a leak or defect is detected, you must repair the leak or 

defect as soon as practicable according to the requirements of paragraphs (e)(9)(i) and (ii) of this 

section, except as provided in paragraph (e)(10) of this section.

(i) A first attempt at repair must be made no later than 5 calendar days after the leak is 

detected.

(ii) Repair must be completed no later than 15 calendar days after the leak is detected.

(10) Delay of repair. Delay of repair of a closed vent system or cover for which leaks or 

defects have been detected is allowed if the repair is technically infeasible without a shutdown, 

or if you determine that emissions resulting from immediate repair would be greater than the 

fugitive emissions likely to result from delay of repair. You must complete repair of such 

equipment by the end of the next shutdown.

(11) Unsafe to inspect requirements. You may designate any parts of the closed vent 

system or cover as unsafe to inspect if the requirements in paragraphs (e)(11)(i) and (ii) of this 

section are met. Unsafe to inspect parts are exempt from the inspection requirements of 

paragraphs (a) through (c) of this section.

(i) You determine that the equipment is unsafe to inspect because inspecting personnel 

would be exposed to an imminent or potential danger as a consequence of complying with 

paragraphs (a), (b), or (c) of this section.

(ii) You have a written plan that requires inspection of the equipment as frequently as 

practicable during safe-to-inspect times.

(12) Difficult to inspect requirements. You may designate any parts of the closed vent 

system or cover as difficult to inspect, if the requirements in paragraphs (e)(12)(i) and (ii) of this 

section are met. Difficult to inspect parts are exempt from the inspection requirements of 

paragraphs (a) through (c) of this section.

(i) You determine that the equipment cannot be inspected without elevating the 

inspecting personnel more than 2 meters above a support surface.
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Appendix: D-8

(ii) You have a written plan that requires inspection of the equipment at least once every

5 years.

(13) Records. Records shall be maintained as specified in this section and in sections that 

reference this section.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: E-1

E VOC Emission Control Device Requirements

E.1 Initial Control Device Compliance Requirements

You must meet the applicable requirements of this section for each control device used to 

comply with VOC emission reduction requirements by the compliance date specified by your 

regulatory authority.

(a) Each control device used to meet the VOC emission reduction requirements must be 

installed according to paragraphs (a)(1) through (3) of this section. As an alternative, you may 

install a control device model tested under section F(d), which meets the criteria in section 

F(d)(11) and section F(e).

(1) Each combustion device (e.g., thermal vapor incinerator, catalytic vapor incinerator, 

boiler, or process heater) must be designed and operated in accordance with one of the 

performance requirements specified in paragraphs (a)(1)(i) through (iv) of this section.

(i) You must reduce the mass content of VOC in the gases vented to the device by 95 

percent by weight or greater as determined in accordance with the requirements of section F(b).

(ii) You must reduce the concentration of TOC in the exhaust gases at the outlet to the 

device to a level equal to or less than 600 parts per million by volume as propane on a dry basis 

corrected to 3 percent oxygen as determined in accordance with the requirements of section F(b).

(iii) You must operate at a minimum temperature of 760°C for a control device that can 

demonstrate a uniform combustion zone temperature during the performance test conducted 

under section F(b).

(iv) If a boiler or process heater is used as the control device, then you must introduce the 

vent stream into the flame zone of the boiler or process heater.

(2) Each vapor recovery device (e.g., carbon adsorption system or condenser) or other 

non-destructive control device must be designed and operated to reduce the mass content of 
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Appendix: E-2

VOC in the gases vented to the device by 95 percent by weight or greater as determined in 

accordance with the requirements of section F. As an alternative to the performance testing 

requirements, you may demonstrate initial compliance by conducting a design analysis for vapor 

recovery devices according to the requirements of section F(c).

(3) You must design and operate a flare in accordance with the requirements of section F.

(b) You must operate each control device installed to control VOC emissions from your 

emissions source in accordance with the requirements specified in paragraphs (b)(1) and (2) of 

this section.

(1) You must operate each control device used to comply with this rule at all times when 

gases, vapors, and fumes are vented from your VOC emissions source through the closed vent 

system to the control device. You may vent more than one source to a control device used to 

comply with this rule.

(2) For each control device monitored in accordance with the requirements of section 

E.2(a) through (g), you must demonstrate continuous compliance according to the requirements 

of section A.4(c) for storage vessels, section C.5(a)(2) for centrifugal compressors, section H.4 

for pneumatic pumps, and as applicable.

(c) For each carbon adsorption system used as a control device to meet the requirements 

of paragraph (a)(2) of this section, you must manage the carbon in accordance with the 

requirements specified in paragraphs (c)(1) or (2) of this section.

(1) Following the compliance date established by your regulatory authority for the source 

using the control device, you must replace all carbon in the control device with fresh carbon on a 

regular, predetermined time interval that is no longer than the carbon service life established 

according to section F(c)(2) or (3) or according to the design required in paragraph (a)(2) of this 

section, for the carbon adsorption system. You must maintain records identifying the schedule 

for replacement and records of each carbon replacement.
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Appendix: E-3

(2) You must either regenerate, reactivate, or burn the spent carbon removed from the 

carbon adsorption system in one of the units specified in paragraphs (c)(2)(i) through (vii) of this 

section.

(i) Regenerate or reactivate the spent carbon in a thermal treatment unit for which you 

have been issued a final permit under 40 CFR part 270 that implements the requirements of 40 

CFR part 264, subpart X.

(ii) Regenerate or reactivate the spent carbon in a thermal treatment unit equipped with 

and operating air 95 percent in accordance with this section.

(iii) Regenerate or reactivate the spent carbon in a thermal treatment unit equipped with 

and operating organic air 95 percent in accordance with an emissions standard for VOC under 

this rule.

(iv) Burn the spent carbon in a hazardous waste incinerator for which the owner or 

operator has been issued a final permit under 40 CFR part 270 that implements the requirements 

of 40 CFR part 264, subpart O.

(v) Burn the spent carbon in a hazardous waste incinerator which you have designed and 

operated in accordance with the requirements of 40 CFR part 265, subpart O.

(vi) Burn the spent carbon in a boiler or industrial furnace for which you have been 

issued a final permit under 40 CFR part 270 that implements the requirements of 40 CFR part 

266, subpart H.

(vii) Burn the spent carbon in a boiler or industrial furnace that you have designed and 

operated in accordance with the interim status requirements of 40 CFR part 266, subpart H.

(d) Each control device used to meet the emission reduction standard in section A.2 for a 

storage vessel must be installed according to paragraphs (d)(1) through (4) of this section, as 

applicable. As an alternative to paragraph (d)(1) of this section, you may install a control device 

model tested under section F(d), which meets the criteria in section F(d)(11) and F(e).
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Appendix: E-4

(1) Each enclosed combustion device (e.g., thermal vapor incinerator, catalytic vapor 

incinerator, boiler, or process heater) must be designed to reduce the mass content of VOC 

emissions by 95.0 percent or greater. You must follow the requirements in paragraphs (d)(1)(i) 

through (iii) of this section.

(i) Ensure that each enclosed combustion device is maintained in a leak free condition.

(ii) Install and operate a continuous burning pilot flame.

(iii) Operate the enclosed combustion device with no visible emissions, except for 

periods not to exceed a total of one minute during any 15 minute period. A visible emissions test 

using section 11 of EPA Method 22, 40 CFR part 60, appendix A, must be performed at least 

once every calendar month, separated by at least 15 days between each test. The observation 

period shall be 15 minutes. Devices failing the visible emissions test must follow manufacturer's 

repair instructions, if available, or best combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair 

and maintenance activities for each unit must be recorded in a maintenance and repair log and 

must be available for inspection. Following return to operation from maintenance or repair 

activity, each device must pass a Method 22, 40 CFR part 60, appendix A, visual observation as 

described in this paragraph.

(2) Each vapor recovery device (e.g., carbon adsorption system or condenser) or other 

non-destructive control device must be designed and operated to reduce the mass content of 

VOC in the gases vented to the device by 95.0 percent by weight or greater. A carbon 

replacement schedule must be included in the design of the carbon adsorption system.

(3) You must operate each control device used to comply with this subpart at all times 

when gases, vapors, and fumes are vented from the storage vessel affected facility through the 

closed vent system to the control device. You may vent more than one affected facility to a 

control device used to comply with this subpart.

(4) Each combustion control device (e.g., thermal vapor incinerator, catalytic vapor 

incinerator, boiler, or process heater) must be designed and operated in accordance with one of 
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Appendix: E-5

the performance requirements specified in paragraphs (i) through (iv) of this section. 

(i) You must reduce the mass content of methane and VOC in the gases vented to the 

device by 95.0 percent by weight or greater as determined in accordance with the requirements 

of section F. 

(ii) You must reduce the concentration of TOC in the exhaust gases at the outlet to the 

device to a level equal to or less than 600 parts per million by volume as propane on a dry basis 

corrected to 3 percent oxygen as determined in accordance with the requirements of section F. 

(iii) You must operate at a minimum temperature of 760°C for a control device that can 

demonstrate a uniform combustion zone temperature during the performance test conducted 

under section F. 

(iv) If a boiler or process heater is used as the control device, then you must introduce the 

vent stream into the flame zone of the boiler or process heater. 

E.2 Continuous Control Device Monitoring Requirements 

You must meet the applicable requirements of this section to demonstrate continuous 

compliance for each control device used to meet VOC emission control requirements.

(a) For each control device used to comply with the VOC emission reduction 

requirements, you must install and operate a continuous parameter monitoring system for each 

control device as specified in paragraphs (c) through (h) of this section, except as provided for in 

paragraph (b) of this section. If you install and operate a flare in accordance with section 

E.1(a)(3), you are exempt from the requirements of paragraphs (e) and (f) of this section.

(b) You are exempt from the monitoring requirements specified in paragraphs (c) through 

(f) of this section for the control devices listed in paragraphs (b)(1) and (2) of this section.

(1) A boiler or process heater in which all vent streams are introduced with the primary

fuel, or used as the primary fuel.
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Appendix: E-6

(2) A boiler or process heater with a design heat input capacity equal to or greater than 44 

megawatts.

(c) If you are required to install a continuous parameter monitoring system, you must 

meet the specifications and requirements in paragraphs (c)(1) through (4) of this section.

(1) Each continuous parameter monitoring system must measure data values at least once 

every hour and record the parameters in paragraphs (c)(1)(i) or (ii) of this section.

(i) Each measured data value.

(ii) Each block average value for each 1-hour period or shorter periods calculated from all 

measured data values during each period. If values are measured more frequently than once per 

minute, a single value for each minute may be used to calculate the hourly (or shorter period) 

block average instead of all measured values.

(2) You must prepare a site-specific monitoring plan that addresses the monitoring 

system design, data collection, and the quality assurance and quality control elements outlined in 

paragraphs (c)(2)(i) through (v) of this section. You must install, calibrate, operate, and maintain 

each continuous parameter monitoring system in accordance with the procedures in your 

approved site-specific monitoring plan.

(i) The performance criteria and design specifications for the monitoring system 

equipment, including the sample interface, detector signal analyzer, and data acquisition and 

calculations.

(ii) Sampling interface (e.g., thermocouple) location such that the monitoring system will 

provide representative measurements.

(iii) Equipment performance checks, system accuracy audits, or other audit procedures.

(iv) On-going operation and maintenance procedures in accordance with provisions in 40 

CFR 60.13(b).
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Appendix: E-7

(v) Ongoing reporting and recordkeeping procedures in accordance with provisions in 40 

CFR 60.7(c), (d), and (f).

(3) You must conduct the continuous parameter monitoring system equipment 

performance checks, system accuracy audits, or other audit procedures specified in the sitespecific monitoring plan at least once every 12 months.

(4) You must conduct a performance evaluation of each continuous parameter monitoring 

system in accordance with the site-specific monitoring plan.

(d) You must install, calibrate, operate, and maintain a device equipped with a continuous 

recorder to measure the values of operating parameters appropriate for the control device as 

specified in either paragraph (d)(1), (2), or (3) of this section.

(1) A continuous monitoring system that measures the operating parameters in 

paragraphs (d)(1)(i) through (viii) of this section, as applicable.

(i) For a thermal vapor incinerator that demonstrates during the performance test 

conducted under section X.F that combustion zone temperature is an accurate indicator of 

performance, a temperature monitoring device equipped with a continuous recorder. The 

monitoring device must have a minimum accuracy of ±1 percent of the temperature being 

monitored in °C, or ±2.5°C, whichever value is greater. You must install the temperature sensor 

at a location representative of the combustion zone temperature.

(ii) For a catalytic vapor incinerator, a temperature monitoring device equipped with a 

continuous recorder. The device must be capable of monitoring temperature at two locations and

have a minimum accuracy of ±1 percent of the temperature being monitored in °C, or ±2.5°C, 

whichever value is greater. You must install one temperature sensor in the vent stream at the 

nearest feasible point to the catalyst bed inlet, and you must install a second temperature sensor 

in the vent stream at the nearest feasible point to the catalyst bed outlet.

(iii) For a flare, a heat sensing monitoring device equipped with a continuous recorder 

that indicates the continuous ignition of the pilot flame.
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Appendix: E-8

(iv) For a boiler or process heater, a temperature monitoring device equipped with a 

continuous recorder. The temperature monitoring device must have a minimum accuracy of ±1 

percent of the temperature being monitored in °C, or ±2.5°C, whichever value is greater. You 

must install the temperature sensor at a location representative of the combustion zone 

temperature.

(v) For a condenser, a temperature monitoring device equipped with a continuous 

recorder. The temperature monitoring device must have a minimum accuracy of ±1 percent of 

the temperature being monitored in °C, or ±2.8°C, whichever value is greater. You must install 

the temperature sensor at a location in the exhaust vent stream from the condenser.

(vi) For a regenerative-type carbon adsorption system, a continuous monitoring system 

that meets the specifications in paragraphs (d)(1)(vi)(A) and (B) of this section.

(A) The continuous parameter monitoring system must measure and record the average 

total regeneration stream mass flow or volumetric flow during each carbon bed regeneration 

cycle. The flow sensor must have a measurement sensitivity of 5 percent of the flow rate or 10 

cubic feet per minute, whichever is greater. You must check the mechanical connections for 

leakage at least every month, and you must perform a visual inspection at least every 3 months of 

all components of the flow continuous parameter monitoring system for physical and operational 

integrity and all electrical connections for oxidation and galvanic corrosion if your flow 

continuous parameter monitoring system is not equipped with a redundant flow sensor; and

(B) The continuous parameter monitoring system must measure and record the average 

carbon bed temperature for the duration of the carbon bed steaming cycle and measure the actual 

carbon bed temperature after regeneration and within 15 minutes of completing the cooling 

cycle. The temperature monitoring device must have a minimum accuracy of ±1 percent of the 

temperature being monitored in °C, or ±2.5°C, whichever value is greater.

(vii) For a non-regenerative-type carbon adsorption system, you must monitor the design 

carbon replacement interval established using a performance test performed as specified in 

section X.F(b). The design carbon replacement interval must be based on the total carbon 

working capacity of the control device and source operating schedule.
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Appendix: E-9

(viii) For a combustion control device whose model is tested under section X.F(d), a 

continuous monitoring system meeting the requirements of paragraphs (d)(1)(viii)(A) through 

(D) of this section.

(A) The continuous monitoring system must measure gas flow rate at the inlet to the 

control device. The monitoring instrument must have an accuracy of ±2 percent or better. The 

flow rate at the inlet to the combustion device must not exceed the maximum or minimum flow 

rate determined by the manufacturer.

(B) A monitoring device that continuously indicates the presence of the pilot flame while 

emissions are routed to the control device.

(C) Devices failing the visible emissions test must follow manufacturer's repair 

instructions, if available, or best combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant operation. All repairs and 

maintenance activities for each unit must be recorded in a maintenance and repair log and must 

be available for inspection.

(D) Following return to operation from maintenance or repair activity, each device must 

pass a Method 22, 40 CFR part 60, appendix A, visual observation as described in paragraph 

(d)(2)(viii)(B) of this section.

(2) An organic monitoring device equipped with a continuous recorder that measures the 

concentration level of organic compounds in the exhaust vent stream from the control device. 

The monitor must meet the requirements of Performance Specification 8 or 9 of 40 CFR part 60, 

appendix B. You must install, calibrate, and maintain the monitor according to the 

manufacturer's specifications.

(3) A continuous monitoring system that measures operating parameters other than those 

specified in paragraph (d)(1) or (2) of this section, upon approval of the regulatory authority.

(e) You must calculate the daily average value for each monitored operating parameter 

for each operating day, using the data recorded by the monitoring system, except for inlet gas 
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: E-10

flow rate. If the emissions unit operation is continuous, the operating day is a 24-hour period. If 

the emissions unit operation is not continuous, the operating day is the total number of hours of 

control device operation per 24-hour period. Valid data points must be available for 75 percent of 

the operating hours in an operating day to compute the daily average.

(f) For each operating parameter monitor installed in accordance with the requirements of 

paragraph (d) of this section, you must comply with paragraph (f)(1) of this section for all 

control devices. When condensers are installed, you must also comply with paragraph (f)(2) of 

this section.

(1) You must establish a minimum operating parameter value or a maximum operating 

parameter value, as appropriate for the control device, to define the conditions at which the 

control device must be operated to continuously achieve the applicable performance 

requirements of section E.1(a). You must establish each minimum or maximum operating 

parameter value as specified in paragraphs (f)(1)(i) through (iii) of this section.

(i) If you conduct performance tests in accordance with the requirements of section F(b) 

to demonstrate that the control device achieves the applicable performance requirements 

specified in section E.1(a), then you must establish the minimum operating parameter value or 

the maximum operating parameter value based on values measured during the performance test 

and supplemented, as necessary, by a condenser design analysis or control device manufacturer 

recommendations or a combination of both.

(ii) If you use a condenser design analysis in accordance with the requirements of section 

F(c) to demonstrate that the control device achieves the applicable performance requirements 

specified in section E.1(a), then you must establish the minimum operating parameter value or 

the maximum operating parameter value based on the condenser design analysis and 

supplemented, as necessary, by the condenser manufacturer's recommendations.

(iii) If you operate a control device where the performance test requirement was met 

under section F(d) to demonstrate that the control device achieves the applicable performance 

requirements specified in section E.1(a), then your control device inlet gas flow rate must not 

exceed the maximum or minimum inlet gas flow rate determined by the manufacturer.
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Appendix: E-11

(2) If you use a condenser as specified in paragraph (d)(1)(v) of this section, you must 

establish a condenser performance curve showing the relationship between condenser outlet 

temperature and condenser control efficiency, according to the requirements of paragraphs 

(f)(2)(i) and (ii) of this section.

(i) If you conduct a performance test in accordance with the requirements of section F(b) 

to demonstrate that the condenser achieves the applicable performance requirements in section 

E.1(a), then the condenser performance curve must be based on values measured during the 

performance test and supplemented as necessary by control device design analysis, or control 

device manufacturer's recommendations, or a combination or both.

(ii) If you use a control device design analysis in accordance with the requirements of 

section F(c)(1) to demonstrate that the condenser achieves the applicable performance

requirements specified in section E.1(a), then the condenser performance curve must be based on 

the condenser design analysis and supplemented, as necessary, by the control device 

manufacturer's recommendations.

(g) A deviation for a given control device is determined to have occurred when the 

monitoring data or lack of monitoring data result in any one of the criteria specified in 

paragraphs (g)(1) through (6) of this section being met. If you monitor multiple operating 

parameters for the same control device during the same operating day and more than one of these 

operating parameters meets a deviation criterion specified in paragraphs (g)(1) through (6) of this 

section, then a single excursion is determined to have occurred for the control device for that

operating day.

(1) A deviation occurs when the daily average value of a monitored operating parameter 

is less than the minimum operating parameter limit (or, if applicable, greater than the maximum 

operating parameter limit) established in paragraph (f)(1) of this section.

(2) If you meet section E.1(a)(2), a deviation occurs when the 365-day average condenser 

efficiency calculated according to the requirements specified in section F(b) is less than 95

percent.
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Appendix: E-12

(3) If you meet section E.1(a)(2) and you have less than 365 days of data, a deviation 

occurs when the average condenser efficiency calculated according to the procedures specified in 

section F(b) is less than 90.0 percent.

(4) A deviation occurs when the monitoring data are not available for at least 75 percent 

of the operating hours in a day.

(5) If the closed vent system contains one or more bypass devices that could be used to 

divert all or a portion of the gases, vapors, or fumes from entering the control device, a deviation 

occurs when the requirements of paragraphs (g)(5)(i) and (ii) of this section are met.

(i) For each bypass line subject to section D.1(b)(3)(i)(A), the flow indicator indicates 

that flow has been detected and that the stream has been diverted away from the control device to 

the atmosphere.

(ii) For each bypass line subject to section D.1(b)(3)(i)(B), if the seal or closure 

mechanism has been broken, the bypass line valve position has changed, the key for the lockand-key type lock has been checked out, or the car-seal has broken.

(6) For a combustion control device whose model is tested under section F(d), a deviation 

occurs when the conditions of paragraphs (g)(6)(i) or (ii) are met.

(i) The inlet gas flow rate exceeds the maximum established during the test conducted 

under section F(d).

(ii) Failure of the monthly visible emissions test conducted under section F(e)(3) occurs.

(h) Each control device used to meet a VOC emission reduction requirement must be 

operated following the manufacturer's written operating instructions, procedures and 

maintenance schedule to ensure good air pollution control practices for minimizing emissions. 

Records of the manufacturer's written operating instructions, procedures, and maintenance 

schedule must be available for inspection.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-1

F Performance Test Procedures

This section applies to the performance testing of control devices used to demonstrate 

compliance with your VOC emission control requirements. You must demonstrate that a control 

device achieves the performance requirements specified for your emissions source using the 

performance test methods and procedures specified in this section. For condensers, you may use 

a design analysis as specified in paragraph (c) of this section in lieu of complying with paragraph 

(b) of this section. In addition, this section contains the requirements for enclosed combustion 

device performance tests conducted by the manufacturer, as relevant and allowed for compliance 

demonstration purposes.

(a) Performance test exemptions. You are exempt from the requirements to conduct 

performance tests and design analyses if you use any of the control devices described in 

paragraphs (a)(1) through (7) of this section.

(1) A flare that is designed and operated in accordance with 40 CFR 60.18(b). You must 

conduct the compliance determination using Method 22, 40 CFR part 60, appendix A-7, to 

determine visible emissions.

(2) A boiler or process heater with a design heat input capacity of 44 megawatts or 

greater.

(3) A boiler or process heater into which the vent stream is introduced with the primary

fuel or is used as the primary fuel.

(4) A boiler or process heater burning hazardous waste for which you have either been 

issued a final permit under 40 CFR part 270 and comply with the requirements of 40 CFR part 

266, subpart H; or you have certified compliance with the interim status requirements of 40 CFR 

part 266, subpart H.

(5) A hazardous waste incinerator for which you have been issued a final permit under 40 

CFR part 270 and comply with the requirements of 40 CFR part 264, subpart O; or you have 

certified compliance with the interim status requirements of 40 CFR part 265, subpart O.
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Appendix: F-2

(6) A performance test is waived in accordance with 40 CFR 60.8(b).

(7) A control device whose model can be demonstrated to meet the performance 

requirements of section E.1(a) through a performance test conducted by the manufacturer, as 

specified in paragraph (d) of this section.

(b) Test methods and procedures. You must use the test methods and procedures 

specified in paragraphs (b)(1) through (5) of this section, as applicable, for each performance test 

conducted to demonstrate that a control device meets the requirements of section E.1(a). You 

must conduct the initial and periodic performance tests according to the schedule specified in 

paragraph (b)(5) of this section.

(1) You must use Method 1 or 1A, 40 CFR part 60, appendix A-1, as appropriate, to 

select the sampling sites specified in paragraphs (b)(1)(i) and (ii) of this section. Any references 

to particulate mentioned in Methods 1 and 1A do not apply to this section.

(i) Sampling sites must be located at the inlet of the first control device, and at the outlet 

of the final control device, to determine compliance with the control device percent reduction 

requirement specified in section E.1(a)(1)(i) or (a)(2).

(ii) The sampling site must be located at the outlet of the combustion device to determine 

compliance with the enclosed combustion device TOC concentration limit specified in section 

E.1(a)(1)(ii).

(2) You must determine the gas volumetric flowrate using Method 2, 2A, 2C, or 2D, 40 

CFR part 60, appendix A-2, as appropriate.

(3) To determine compliance with the control device percent reduction performance 

requirement in section E.1(a)(1)(i) or (a)(2), you must use Method 25A at 40 CFR part 60, 

appendix A-7. You must use the procedures in paragraphs (b)(3)(i) through (iv) of this section to 

calculate percent reduction efficiency.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-3

(i) For each run, you must take either an integrated sample or a minimum of four grab 

samples per hour. If grab sampling is used, then the samples must be taken at approximately

equal intervals in time, such as 15-minute intervals during the run.

(ii) You must compute the mass rate of TOC (minus methane and ethane) using the 

equations and procedures specified in paragraphs (b)(3)(ii)(A) and (B) of this section.

(A) You must use the following equations:

Where:

Ei, Eo = Mass rate of TOC (minus methane and ethane) at the inlet and outlet of the 

control device, respectively, dry basis, kilogram per hour.

K2 = Constant, 2.494 × 10−6 (parts per million) (gram-mole per standard cubic meter) 

(kilogram/gram) (minute/hour), where standard temperature (gram-mole per standard 

cubic meter) is 20°C.

Cij, Coj = Concentration of sample component j of the gas stream at the inlet and outlet of 

the control device, respectively, dry basis, parts per million by volume.

Mij, Moj = Molecular weight of sample component j of the gas stream at the inlet and 

outlet of the control device, respectively, gram/gram-mole.

Qi, Qo = Flowrate of gas stream at the inlet and outlet of the control device, respectively, 

dry standard cubic meter per minute.

n = Number of components in sample.

i

n

j 1

Ei K2 CijMij Q















 

o

n

j 1

Eo K2 CojMoj Q















 
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-4

(B) When calculating the TOC mass rate, you must sum all organic compounds (minus 

methane and ethane) measured by Method 25A, 40 CFR part 60, appendix A-7 using the 

equations in paragraph (b)(3)(ii)(A) of this section.

(iii) You must calculate the percent reduction in TOC (minus methane and ethane) as 

follows:

Where:

Rcd = Control efficiency of control device, percent.

Ei = Mass rate of TOC (minus methane and ethane) at the inlet to the control device as 

calculated under paragraph (b)(3)(ii) of this section, kilograms TOC per hour or 

kilograms HAP per hour.

Eo = Mass rate of TOC (minus methane and ethane) at the outlet of the control device, as 

calculated under paragraph (b)(3)(ii) of this section, kilograms TOC per hour per hour.

(iv) If the vent stream entering a boiler or process heater with a design capacity less than 

44 megawatts is introduced with the combustion air or as a secondary fuel, you must determine 

the weight-percent reduction of TOC (minus methane and ethane) across the device by 

comparing the TOC (minus methane and ethane) in all combusted vent streams and primary and 

secondary fuels with the TOC (minus methane and ethane) exiting the device, respectively.

(4) You must use Method 25A, 40 CFR part 60, appendix A-7 to measure TOC (minus 

methane and ethane) to determine compliance with the enclosed combustion device total VOC 

concentration limit specified in section E.1(a)(1)(ii). You must calculate parts per million by

volume concentration and correct to 3 percent oxygen, using the procedures in paragraphs 

(b)(4)(i) through (iii) of this section.

x 100%

E

E E

R

i

i o

cd




***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-5

(i) For each run, you must take either an integrated sample or a minimum of four grab 

samples per hour. If grab sampling is used, then the samples must be taken at approximately

equal intervals in time, such as 15-minute intervals during the run.

(ii) You must calculate the TOC concentration for each run as follows:

Where:

CTOC = Concentration of total organic compounds minus methane and ethane, dry basis, 

parts per million by volume.

Cji = Concentration of sample component j of sample I dry basis, parts per million by

volume. 

n = Number of components in the sample.

x = Number of samples in the sample run.

(iii) You must correct the TOC concentration to 3 percent oxygen as specified in 

paragraphs (b)(4)(iii)(A) and (B) of this section.

(A) You must use the emission rate correction factor for excess air, integrated sampling 

and analysis procedures of Method 3A or 3B at 40 CFR part 60, appendix A, ASTM D6522-00 

(Reapproved 2005), or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) 

(incorporated by reference as specified in §60.17) to determine the oxygen concentration. The 

samples must be taken during the same time that the samples are taken for determining TOC 

concentration.

(B) You must correct the TOC concentration for percent oxygen as follows:



























x

i 1

n

j 1

ji

TOC

x

C

C





















2d

c m

20.9 %O

17.9

C C
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-6

Where:

Cc = TOC concentration corrected to 3 percent oxygen, dry basis, parts per million by

volume.

Cm = TOC concentration, dry basis, parts per million by volume.

%O2d = Concentration of oxygen, dry basis, percent by volume.

(5) You must conduct performance tests according to the schedule specified in 

paragraphs (b)(5)(i) and (ii) of this section.

(i) You must conduct an initial performance test within 180 days after the compliance 

date for your source. 

(ii) You must conduct periodic performance tests for all control devices required to 

conduct initial performance tests except as specified in paragraphs (b)(5)(ii)(A) and (B) of this 

section. You must conduct the first periodic performance test no later than 60 months after the 

initial performance test required in paragraph (b)(5)(i) of this section. You must conduct 

subsequent periodic performance tests at intervals no longer than 60 months following the 

previous periodic performance test or whenever you desire to establish a new operating limit. 

Combustion control devices meeting the criteria in either paragraph (b)(5)(ii)(A) or (B) of this 

section are not required to conduct periodic performance tests.

(A) A control device whose model is tested under, and meets the criteria of paragraph (d) 

of this section.

(B) A combustion control device tested under paragraph (b) of this section that meets the 

outlet TOC performance level specified in section E.1(a)(1)(ii) and that establishes a correlation 

between firebox or combustion chamber temperature and the TOC performance level.

(c) Control device design analysis to meet the requirements of section E.1(a). (1) For a 

condenser, the design analysis must include an analysis of the vent stream composition, 

constituent concentrations, flowrate, relative humidity, and temperature, and must establish the 

design outlet organic compound concentration level, design average temperature of the 
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-7

condenser exhaust vent stream, and the design average temperatures of the coolant fluid at the 

condenser inlet and outlet.

(2) For a regenerable carbon adsorption system, the design analysis shall include the vent 

stream composition, constituent concentrations, flowrate, relative humidity, and temperature, and 

shall establish the design exhaust vent stream organic compound concentration level, adsorption 

cycle time, number and capacity of carbon beds, type and working capacity of activated carbon 

used for the carbon beds, design total regeneration stream flow over the period of each complete 

carbon bed regeneration cycle, design carbon bed temperature after regeneration, design carbon 

bed regeneration time, and design service life of the carbon.

(3) For a non-regenerable carbon adsorption system, such as a carbon canister, the design 

analysis shall include the vent stream composition, constituent concentrations, flowrate, relative 

humidity, and temperature, and shall establish the design exhaust vent stream organic compound 

concentration level, capacity of the carbon bed, type and working capacity of activated carbon 

used for the carbon bed, and design carbon replacement interval based on the total carbon 

working capacity of the control device and source operating schedule. In addition, these systems 

will incorporate dual carbon canisters in case of emission breakthrough occurring in one canister.

(4) If you and the regulated authority do not agree on a demonstration of control device 

performance using a design analysis, then you must perform a performance test in accordance 

with the requirements of paragraph (b) of this section to resolve the disagreement. The regulatory

authority may choose to have an authorized representative observe the performance test.

(d) Performance testing for combustion control devices—manufacturers' performance 

test. (1) This paragraph applies to the performance testing of a combustion control device 

conducted by the device manufacturer. The manufacturer must demonstrate that a specific model 

of control device achieves the performance requirements in paragraph (d)(11) of this section by

conducting a performance test as specified in paragraphs (d)(2) through (10) of this section. You 

must submit a test report for each combustion control device in accordance with the requirements 

in paragraph (d)(12) of this section. 
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-8

(2) Performance testing must consist of three one-hour (or longer) test runs for each of 

the four firing rate settings specified in paragraphs (d)(2)(i) through (iv) of this section, making a 

total of 12 test runs per test. Propene (propylene) gas must be used for the testing fuel. All fuel 

analyses must be performed by an independent third-party laboratory (not affiliated with the 

control device manufacturer or fuel supplier).

(i) 90-100 percent of maximum design rate (fixed rate).

(ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70 percent of the 

maximum design rate. During the first 5 minutes, incrementally ramp the firing rate to 100 

percent of the maximum design rate. Hold at 100 percent for 5 minutes. In the 10-15 minute time 

range, incrementally ramp back down to 70 percent of the maximum design rate. Repeat three 

more times for a total of 60 minutes of sampling.

(iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30 percent of the 

maximum design rate. During the first 5 minutes, incrementally ramp the firing rate to 70 percent 

of the maximum design rate. Hold at 70 percent for 5 minutes. In the 10-15 minute time range, 

incrementally ramp back down to 30 percent of the maximum design rate. Repeat three more 

times for a total of 60 minutes of sampling.

(iv) 0-30-0 percent (ramp up, ramp down). Begin the test at the minimum firing rate. 

During the first 5 minutes, incrementally ramp the firing rate to 30 percent of the maximum 

design rate. Hold at 30 percent for 5 minutes. In the 10-15 minute time range, incrementally

ramp back down to the minimum firing rate. Repeat three more times for a total of 60 minutes of 

sampling.

(3) All models employing multiple enclosures must be tested simultaneously and with all 

burners operational. Results must be reported for each enclosure individually and for the average 

of the emissions from all interconnected combustion enclosures/chambers. Control device 

operating data must be collected continuously throughout the performance test using an 

electronic Data Acquisition System. A graphic presentation or strip chart of the control device 

operating data and emissions test data must be included in the test report in accordance with 
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-9

paragraph (d)(12) of this section. Inlet fuel meter data may be manually recorded provided that 

all inlet fuel data readings are included in the final report.

(4) Inlet testing must be conducted as specified in paragraphs (d)(4)(i) and (ii) of this 

section.

(i) The inlet gas flow metering system must be located in accordance with Method 2A, 40 

CFR part 60, appendix A-1, (or other approved procedure) to measure inlet gas flow rate at the 

control device inlet location. You must position the fitting for filling fuel sample containers a 

minimum of eight pipe diameters upstream of any inlet gas flow monitoring meter.

(ii) Inlet flow rate must be determined using Method 2A, 40 CFR part 60, appendix A-1. 

Record the start and stop reading for each 60-minute THC test. Record the gas pressure and 

temperature at 5-minute intervals throughout each 60-minute test.

(5) Inlet gas sampling must be conducted as specified in paragraphs (d)(5)(i) and (ii) of 

this section.

(i) At the inlet gas sampling location, securely connect a Silonite-coated stainless steel 

evacuated canister fitted with a flow controller sufficient to fill the canister over a 3-hour period. 

Filling must be conducted as specified in paragraphs (d)(5)(i)(A) through (C) of this section.

(A) Open the canister sampling valve at the beginning of each test run, and close the 

canister at the end of each test run.

(B) Fill one canister across the three test runs such that one composite fuel sample exists 

for each test condition.

(C) Label the canisters individually and record sample information on a chain of custody

form.

(ii) Analyze each inlet gas sample using the methods in paragraphs (d)(5)(ii)(A) through 

(C) of this section. You must include the results in the test report required by paragraph (d)(12) 

of this section.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-10

(A) Hydrocarbon compounds containing between one and five atoms of carbon plus 

benzene using ASTM D1945-03.

(B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide (CO2), nitrogen (N2), oxygen 

(O2) using ASTM D1945-03.

(C) Higher heating value using ASTM D3588-98 or ASTM D4891-89.

(6) Outlet testing must be conducted in accordance with the criteria in paragraphs 

(d)(6)(i) through (v) of this section.

(i) Sample and flow rate must be measured in accordance with paragraphs (d)(6)(i)(A) 

through (B) of this section.

(A) The outlet sampling location must be a minimum of four equivalent stack diameters 

downstream from the highest peak flame or any other flow disturbance, and a minimum of one 

equivalent stack diameter upstream of the exit or any other flow disturbance. A minimum of two 

sample ports must be used.

(B) Flow rate must be measured using Method 1, 40 CFR part 60, appendix A-1 for 

determining flow measurement traverse point location, and Method 2, 40 CFR part 60, appendix 

A-1 for measuring duct velocity. If low flow conditions are encountered (i.e., velocity pressure 

differentials less than 0.05 inches of water) during the performance test, a more sensitive 

manometer must be used to obtain an accurate flow profile.

(ii) Molecular weight and excess air must be determined as specified in paragraph (d)(7) 

of this section.

(iii) Carbon monoxide must be determined as specified in paragraph (d)(8) of this section.

(iv) THC must be determined as specified in paragraph (d)(9) of this section.

(v) Visible emissions must be determined as specified in paragraph (d)(10) of this 

section.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-11

(7) Molecular weight and excess air determination must be performed as specified in 

paragraphs (d)(7)(i) through (iii) of this section.

(i) An integrated bag sample must be collected during the Method 4, 40 CFR part 60, 

appendix A-3, moisture test following the procedure specified in paragraphs (d)(7)(i)(A) and (B) 

of this section. Analyze the bag sample using a gas chromatograph-thermal conductivity detector 

(GC-TCD) analysis meeting the criteria in paragraphs (d)(7)(i)(C) and (D) of this section.

(A) Collect the integrated sample throughout the entire test, and collect representative 

volumes from each traverse location.

(B) Purge the sampling line with stack gas before opening the valve and beginning to fill 

the bag. Clearly label each bag and record sample information on a chain of custody form.

(C) The bag contents must be vigorously mixed prior to the gas chromatograph analysis.

(D) The GC-TCD calibration procedure in Method 3C, 40 CFR part 60, appendix A, 

must be modified by using EPA Alt-045 as follows: For the initial calibration, triplicate 

injections of any single concentration must agree within 5 percent of their mean to be valid. The 

calibration response factor for a single concentration recheck must be within 10 percent of the 

original calibration response factor for that concentration. If this criterion is not met, repeat the 

initial calibration using at least three concentration levels.

(ii) Calculate and report the molecular weight of oxygen, carbon dioxide, methane, and 

nitrogen in the integrated bag sample and include in the test report specified in paragraph (d)(12) 

of this section. Moisture must be determined using Method 4, 40 CFR part 60, appendix A-3. 

Traverse both ports with the Method 4, 40 CFR part 60, appendix A-3, sampling train during 

each test run. Ambient air must not be introduced into the Method 3C, 40 CFR part 60, appendix 

A-2, integrated bag sample during the port change.

(iii) Excess air must be determined using resultant data from the EPA Method 3C tests 

and EPA Method 3B, 40 CFR part 60, appendix A, equation 3B-1.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-12

(8) Carbon monoxide must be determined using Method 10, 40 CFR part 60, appendix A. 

Run the test simultaneously with Method 25A, 40 CFR part 60, appendix A-7 using the same 

sampling points. An instrument range of 0-10 parts per million by volume-dry (ppmvd) is 

recommended.

(9) Total hydrocarbon determination must be performed as specified by in paragraphs 

(d)(9)(i) through (vii) of this section.

(i) Conduct THC sampling using Method 25A, 40 CFR part 60, appendix A-7, except 

that the option for locating the probe in the center 10 percent of the stack is not allowed. The 

THC probe must be traversed to 16.7 percent, 50 percent, and 83.3 percent of the stack diameter 

during each test run.

(ii) A valid test must consist of three Method 25A, 40 CFR part 60, appendix A-7, tests, 

each no less than 60 minutes in duration.

(iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane) measurement range is 

preferred; as an alternative a 0-30 ppmvw (as carbon) measurement range may be used.

(iv) Calibration gases must be propane in air and be certified through EPA Protocol 1—

“EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” 

September 1997, as amended August 25, 1999, EPA-600/R-97/121(or more recent if updated 

since 1999).

(v) THC measurements must be reported in terms of ppmvw as propane.

(vi) THC results must be corrected to 3 percent CO2, as measured by Method 3C, 40 CFR 

part 60, appendix A-2. You must use the following equation for this diluent concentration 

correction:



















meas

corr meas CO

C C

2

3
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

Appendix: F-13

Where:

Cmeas = The measured concentration of the pollutant.

CO2meas = The measured concentration of the CO2 diluent.

3 = The corrected reference concentration of CO2 diluent.

Ccorr = The corrected concentration of the pollutant.

(vii) Subtraction of methane or ethane from the THC data is not allowed in determining 

results.

(10) Visible emissions must be determined using Method 22, 40 CFR part 60, appendix 

A. The test must be performed continuously during each test run. A digital color photograph of 

the exhaust point, taken from the position of the observer and annotated with date and time, must 

be taken once per test run and the 12 photos included in the test report specified in paragraph 

(d)(12) of this section.

(11) Performance test criteria. (i) The control device model tested must meet the criteria 

in paragraphs (d)(11)(i)(A) through (D) of this section. These criteria must be reported in the test 

report required by paragraph (d)(12) of this section.

(A) Method 22, 40 CFR part 60, appendix A, results under paragraph (d)(10) of this 

section with no indication of visible emissions.

(B) Average Method 25A, 40 CFR part 60, appendix A, results under paragraph (d)(9) of 

this section equal to or less than 10.0 ppmvw THC as propane corrected to 3.0 percent CO2.

(C) Average CO emissions determined under paragraph (d)(8) of this section equal to or 

less than 10 parts ppmvd, corrected to 3.0 percent CO2.

(D) Excess combustion air determined under paragraph (d)(7) of this section equal to or 

greater than 150 percent.
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Appendix: F-14

(ii) The manufacturer must determine a maximum inlet gas flow rate which must not be 

exceeded for each control device model to achieve the criteria in paragraph (d)(11)(iii) of this 

section. The maximum inlet gas flow rate must be included in the test report required by 

paragraph (d)(12) of this section.

(iii) A control device meeting the criteria in paragraph (d)(11)(i)(A) through (D) of this 

section must demonstrate a destruction efficiency of 95 percent for VOC regulated under this 

rule.

(12) The owner or operator of a combustion control device model tested under this 

paragraph must submit the information listed in paragraphs (d)(12)(i) through (vi) in the test 

report. Owners or operators who claim that any of the performance test information being 

submitted is confidential business information (CBI) must submit a complete file including 

information claimed to be CBI, on a compact disc, flash drive, or other commonly used 

electronic storage media to the EPA. The electronic media must be clearly marked as CBI and 

mailed to Attn: CBI Officer; OAQPS CBIO Room 521; 109 T.W. Alexander Drive; RTP, NC 

27711. The same file with the CBI omitted must be submitted to Oil_and_Gas_PT@EPA.GOV.

(i) A full schematic of the control device and dimensions of the device components.

(ii) The maximum net heating value of the device.

(iii) The test fuel gas flow range (in both mass and volume). Include the maximum 

allowable inlet gas flow rate.

(iv) The air/stream injection/assist ranges, if used.

(v) The test conditions listed in paragraphs (d)(12)(v)(A) through (O) of this section, as 

applicable for the tested model.

(A) Fuel gas delivery pressure and temperature.

(B) Fuel gas moisture range.
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Appendix: F-15

(C) Purge gas usage range.

(D) Condensate (liquid fuel) separation range.

(E) Combustion zone temperature range. This is required for all devices that measure this 

parameter.

(F) Excess combustion air range.

(G) Flame arrestor(s).

(H) Burner manifold.

(I) Pilot flame indicator.

(J) Pilot flame design fuel and calculated or measured fuel usage.

(K) Tip velocity range.

(L) Momentum flux ratio.

(M) Exit temperature range.

(N) Exit flow rate.

(O) Wind velocity and direction.

(vi) The test report must include all calibration quality assurance/quality control data, 

calibration gas values, gas cylinder certification, strip charts, or other graphic presentations of the 

data annotated with test times and calibration values.

(e) Continuous compliance for combustion control devices tested by the manufacturer in 

accordance with paragraph (d) of this section. This paragraph applies to the demonstration of 

compliance for a combustion control device tested under the provisions in paragraph (d) of this 

section. Owners or operators must demonstrate that a control device achieves the performance 
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Appendix: F-16

requirements in (d)(11) of this section by installing a device tested under paragraph (d) of this 

section and complying with the criteria specified in paragraphs (e)(1) through (7) of this section.

(1) The inlet gas flow rate must be equal to or less than the maximum specified by the 

manufacturer.

(2) A pilot flame must be present at all times of operation.

(3) Devices must be operated with no visible emissions, except for periods not to exceed 

a total of 1 minute during any 15-minute period. A visible emissions test conducted according to

section 11 of EPA Method 22, 40 CFR part 60, appendix A, must be performed at least once 

every calendar month, separated by at least 15 days between each test. The observation period 

shall be 15 minutes. 

(4) Devices failing the visible emissions test must follow manufacturer's repair 

instructions, if available, or best combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair 

and maintenance activities for each unit must be recorded in a maintenance and repair log and 

must be available for inspection. 

(5) Following return to operation from maintenance or repair activity, each device must 

pass an EPA Method 22, 40 CFR part 60, appendix A, visual observation as described in 

paragraph (e)(3) of this section.

(6) If the owner or operator operates a combustion control device model tested under this 

section, an electronic copy of the performance test results required by this section shall be 

submitted via email to Oil_and_Gas_PT@EPA.GOV unless the test results for that model of 

combustion control device are posted at the following Web site: epa.gov/airquality/oilandgas/.

(7) Ensure that each enclosed combustion control device is maintained in a leak free 

condition.
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Appendix: G-1

G Equipment Component VOC Leaks at Natural Gas Processing Plants

G.1 Applicability

(a) The group of all equipment, except compressors, within a process unit located at an 

onshore natural gas processing plant.

(b) Equipment associated with a compressor station, dehydration unit, sweetening unit, 

underground storage vessel, field gas gathering system, or liquefied natural gas unit is covered 

by the requirements of section G.2 if it is located at an onshore natural gas processing plant. 

Equipment not located at the onshore natural gas processing plant site is exempt from the 

requirements of section G.2.

(c) The equipment within a process unit subject to VOC emission control requirements 

located at onshore natural gas processing plants is exempt from this section if they are subject to 

and controlled according to subparts VVa, GGG or GGGa of 40 CFR part 60.

G.2 What VOC Emission Requirements Apply to Equipment Components 

at a Natural Gas Processing Plant?

(a) You must comply with the requirements of sections G.5.1 (a), (b), and (d), and 

sections G.5.4 through G.5.11, except as provided in section G.3.

(b) You may elect to comply with the requirements of sections G.6.1 and G.6.2, as an 

alternative.

(c) You must comply with the provisions of section G.7 of this section except as provided 

in paragraph (e) of this section.

(d) You must comply with the provisions of section G.9.8 and G.9.9 of this section 

except as provided in section G.3.
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Appendix: G-2

(e) You must use the following instead of section G.7(d)(1): Each piece of equipment is 

presumed to be in VOC service or in wet gas service unless an owner or operator demonstrates 

that the piece of equipment is not in VOC service or in wet gas service. For a piece of equipment 

to be considered not in VOC service, it must be determined that the VOC content can be 

reasonably expected never to exceed 10.0 percent by weight. For a piece of equipment to be 

considered in wet gas service, it must be determined that it contains or contacts the field gas 

before the extraction step in the process. For purposes of determining the percent VOC content 

of the process fluid that is contained in or contacts a piece of equipment, procedures that 

conform to the methods described in ASTM E169-93, E168-92, or E260-96 must be used.

G.3 What Exceptions Apply to the Equipment Leak VOC Emission Control 

Requirements for Equipment Components at Natural Gas Processing Plants?

(a) You may comply with the following exceptions to the provisions of section G.2(a) 

and (b).

(b)(1) Each pressure relief device in gas/vapor service may be monitored quarterly and 

within 5 days after each pressure release to detect leaks by the methods specified in section 

G.7(b) except as provided in section G.2(c) and in paragraph (b)(4) of this section, and section 

G.5.4(a) through (c) of this rule.

(2) If an instrument reading of 500 ppm or greater is measured, a leak is detected.

(3)(i) When a leak is detected, it must be repaired as soon as practicable, but no later than 

15 calendar days after it is detected, except as provided in section G.5.9.

(ii) A first attempt at repair must be made no later than 5 calendar days after each leak is 

detected.

(4)(i) Any pressure relief device that is located in a nonfractionating plant that is 

monitored only by non-plant personnel may be monitored after a pressure release the next time 

the monitoring personnel are on-site, instead of within 5 days as specified in paragraph (b)(1) of 

this section and section G.9.4(b)(1).
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Appendix: G-3

(ii) No pressure relief device described in paragraph (b)(4)(i) of this section must be 

allowed to operate for more than 30 days after a pressure release without monitoring.

(c) Sampling connection systems are exempt from the requirements of section G.5.9.

(d) Pumps in light liquid service, valves in gas/vapor and light liquid service, pressure 

relief devices in gas/vapor service, and connectors in gas/vapor service and in light liquid service 

that are located at a non-fractionating plant that does not have the design capacity to process 

283,200 standard cubic meters per day (scmd) (10 million standard cubic feet per day) or more 

of field gas are exempt from the routine monitoring requirements of sections G.5.2(a)(1), G.5.7 

(a), G.5.11(a), and paragraph (b)(1) of this section.

(e) Pumps in light liquid service, valves in gas/vapor and light liquid service, pressure 

relief devices in gas/vapor service, and connectors in gas/vapor service and in light liquid service 

within a process unit that is located in the Alaskan North Slope are exempt from the routine 

monitoring requirements of sections G.5.2 (a)(1), G.5.7(a), G.5.11(a), and paragraph (b)(1) of 

this section.

(f) An owner or operator may use the following provisions instead of section G.7(e):

(1) Equipment is in heavy liquid service if the weight percent evaporated is 10 percent or 

less at 150°C (302°F) as determined by ASTM Method D86-96.

(2) Equipment is in light liquid service if the weight percent evaporated is greater than 10 

percent at 150°C (302°F) as determined by ASTM Method D86-96.

(g) An owner or operator may use the following provisions instead of section G.7(b)(2): 

A calibration drift assessment shall be performed, at a minimum, at the end of each monitoring 

day. Check the instrument using the same calibration gas(es) that were used to calibrate the 

instrument before use. Follow the procedures specified in USEPA Method 21 of appendix A-7 of 

this part, Section 10.1, except do not adjust the meter readout to correspond to the calibration gas 

value. Record the instrument reading for each scale used as specified in section G.8 (e)(8). 

Divide these readings by the initial calibration values for each scale and multiply by 100 to 
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Appendix: G-4

express the calibration drift as a percentage. If any calibration drift assessment shows a negative 

drift of more than 10 percent from the initial calibration value, then all equipment monitored 

since the last calibration with instrument readings below the appropriate leak definition and 

above the leak definition multiplied by (100 minus the percent of negative drift/divided by 100) 

must be re-monitored. If any calibration drift assessment shows a positive drift of more than 10 

percent from the initial calibration value, then, at the owner/operator's discretion, all equipment 

since the last calibration with instrument readings above the appropriate leak definition and 

below the leak definition multiplied by (100 plus the percent of positive drift/divided by 100) 

may be re-monitored.

G.4 How Do I Demonstrate Initial and Continued Compliance with the 

VOC Emission Control Requirements for Equipment Components at Natural 

Gas Processing Plants?

You must determine initial compliance with the standards for each equipment component 

subject to VOC emission control requirements by the compliance date specified by your 

regulatory authority by complying with the requirements specified in paragraphs (a) through (i) 

of this section.

For equipment components subject to VOC emission control requirements at natural gas 

processing plants, initial and continuous compliance with the VOC requirements is demonstrated 

if you are in compliance with the requirements of section G.2.

G.5 What VOC Emission Control Requirements Apply to Equipment 

Components at Natural Gas Processing Plants

G.5.1 VOC Emission Control Requirements: General

(a) Each owner or operator subject to the provisions of this rule shall demonstrate 

compliance with the requirements of sections G.5.1 through G.5.10 for all equipment within 180 

days of the compliance date.
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Appendix: G-5

(b) Compliance with sections G.5.1 to G.5.10 will be determined by review of records 

and reports, review of performance test results, and inspection using the methods and procedures 

specified in G.7.

(c)(1) An owner or operator may request a determination of equivalence of a means of 

emission limitation to the requirements of sections G.5.2, G.5.3, G.5.5, G.5.6, G.5.7, G.5.8, and 

G.5.10.

(2) If the permitting authority makes a determination that a means of emission limitation 

is at least equivalent to the requirements of sections G.5.2, G.5.3, G.5.5, G.5.6, G.5.7, G.5.8, or 

section G.5.10, an owner or operator shall comply with the requirements of that determination.

(d) Equipment that is in vacuum service is excluded from the requirements of sections 

G.5.2 through G.5.10 if it is identified as required in section G.8(e)(5).

(e) Equipment that an owner or operator designates as being in VOC service less than 

300 hr/yr is excluded from the requirements of sections G.5.2 through G.5.11 if it is identified as 

required in section G.8(e)(6) and it meets any of the conditions specified in paragraphs (e)(1) 

through (3) of this section.

(1) The equipment is in VOC service only during startup and shutdown, excluding startup 

and shutdown between batches of the same campaign for a batch process.

(2) The equipment is in VOC service only during process malfunctions or other 

emergencies.

(3) The equipment is backup equipment that is in VOC service only when the primary

equipment is out of service.

(f)(1) If a dedicated batch process unit operates less than 365 days during a year, an 

owner or operator may monitor to detect leaks from pumps, valves, and open-ended valves or 

lines at the frequency specified in the following table instead of monitoring as specified in 

sections G.5.2, G.5.7, and G.5.2:
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Appendix: G-6

Operating Time

(percent of hours 

during year)

Equivalent Monitoring Frequency Time in Use

Monthly Quarterly Semiannually

0 to <25 Quarterly Annually Annually

25 to <50 Quarterly Semiannually Annually

50 to <75 Bimonthly Three Quarters Semiannually

75 to 100 Monthly Quarterly Semiannually

(2) Pumps and valves that are shared among two or more batch process units that are 

subject to this subpart may be monitored at the frequencies specified in paragraph (f)(1) of this 

section, provided the operating time of all such process units is considered.

(3) The monitoring frequencies specified in paragraph (f)(1) of this section are not 

requirements for monitoring at specific intervals and can be adjusted to accommodate process 

operations. An owner or operator may monitor at any time during the specified monitoring 

period (e.g., month, quarter, year), provided the monitoring is conducted at a reasonable interval 

after completion of the last monitoring campaign. Reasonable intervals are defined in paragraphs 

(f)(3)(i) through (iv) of this section.

(i) When monitoring is conducted quarterly, monitoring events must be separated by at 

least 30 calendar days.

(ii) When monitoring is conducted semiannually (i.e., once every 2 quarters), monitoring 

events must be separated by at least 60 calendar days.

(iii) When monitoring is conducted in 3 quarters per year, monitoring events must be 

separated by at least 90 calendar days.

(iv) When monitoring is conducted annually, monitoring events must be separated by at 

least 120 calendar days.

(g) If the storage vessel is shared with multiple process units, the process unit with the 

greatest annual amount of stored materials (predominant use) is the process unit the storage 

vessel is assigned to. If the storage vessel is shared equally among process units, and one of the 

process units has equipment subject to this subpart, the storage vessel is assigned to that process 
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Appendix: G-7

unit. If the storage vessel is shared equally among process units, none of which have equipment 

subject to this subpart of this part, the storage vessel is assigned to any process unit subject to 

subpart VV of this part. If the predominant use of the storage vessel varies from year to year, 

then the owner or operator must estimate the predominant use initially and reassess every 3 

years. The owner or operator must keep records of the information and supporting calculations 

that show how predominant use is determined. All equipment on the storage vessel must be 

monitored when in VOC service.

G.5.2 What Equipment Component VOC Emission Control Requirements Apply to 

Pumps in Light Liquid Service?

(a)(1) Each pump in light liquid service shall be monitored monthly to detect leaks by the 

methods specified in section G.7(b), except as provided in sections G.5.1(c) and (f) and 

paragraphs (d), (e), and (f) of this section. A pump that begins operation in light liquid service 

after the compliance date for the process unit must be monitored for the first time within 30 days 

after the end of its startup period, except for a pump that replaces a leaking pump and except as 

provided in section G.5.1(c) and paragraphs (d), (e), and (f) of this section.

(2) Each pump in light liquid service shall be checked by visual inspection each calendar 

week for indications of liquids dripping from the pump seal, except as provided in section 

G.5.1(f).

(b)(1) The instrument reading that defines a leak is specified in paragraphs (b)(1)(i) and 

(ii) of this section.

(i) 5,000 parts per million (ppm) or greater for pumps handling polymerizing monomers;

(ii) 2,000 ppm or greater for all other pumps.

(2) If there are indications of liquids dripping from the pump seal, the owner or operator 

shall follow the procedure specified in either paragraph (b)(2)(i) or (ii) of this section. This 

requirement does not apply to a pump that was monitored after a previous weekly inspection and 
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Appendix: G-8

the instrument reading was less than the concentration specified in paragraph (b)(1)(i) or (ii) of 

this section, whichever is applicable.

(i) Monitor the pump within 5 days as specified in section G.7(b). A leak is detected if 

the instrument reading measured during monitoring indicates a leak as specified in paragraph 

(b)(1)(i) or (ii) of this section, whichever is applicable. The leak shall be repaired using the 

procedures in paragraph (c) of this section.

(ii) Designate the visual indications of liquids dripping as a leak, and repair the leak using 

either the procedures in paragraph (c) of this section or by eliminating the visual indications of 

liquids dripping.

(c)(1) When a leak is detected, it shall be repaired as soon as practicable, but not later 

than 15 calendar days after it is detected, except as provided in section G.5.9.

(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is 

detected. First attempts at repair include, but are not limited to, the practices described in 

paragraphs (c)(2)(i) and (ii) of this section, where practicable.

(i) Tightening the packing gland nuts;

(ii) Ensuring that the seal flush is operating at design pressure and temperature.

(d) Each pump equipped with a dual mechanical seal system that includes a barrier fluid 

system is exempt from the requirements of paragraph (a) of this section, provided the 

requirements specified in paragraphs (d)(1) through (6) of this section are met.

(1) Each dual mechanical seal system is:

(i) Operated with the barrier fluid at a pressure that is at all times greater than the pump 

stuffing box pressure; or
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Appendix: G-9

(ii) Equipped with a barrier fluid degassing reservoir that is routed to a process or fuel gas 

system or connected by a closed vent system to a control device that complies with the 

requirements of section G.5.10; or

(iii) Equipped with a system that purges the barrier fluid into a process stream with zero 

VOC emissions to the atmosphere.

(2) The barrier fluid system is in heavy liquid service or is not in VOC service.

(3) Each barrier fluid system is equipped with a sensor that will detect failure of the seal 

system, the barrier fluid system, or both.

(4)(i) Each pump is checked by visual inspection, each calendar week, for indications of 

liquids dripping from the pump seals.

(ii) If there are indications of liquids dripping from the pump seal at the time of the 

weekly inspection, the owner or operator shall follow the procedure specified in either paragraph 

(d)(4)(ii)(A) or (B) of this section prior to the next required inspection.

(A) Monitor the pump within 5 days as specified in section G.7(b) to determine if there is 

a leak of VOC in the barrier fluid. If an instrument reading of 2,000 ppm or greater is measured, 

a leak is detected.

(B) Designate the visual indications of liquids dripping as a leak.

(5)(i) Each sensor as described in paragraph (d)(3) is checked daily or is equipped with 

an audible alarm.

(ii) The owner or operator determines, based on design considerations and operating 

experience, a criterion that indicates failure of the seal system, the barrier fluid system, or both.

(iii) If the sensor indicates failure of the seal system, the barrier fluid system, or both, 

based on the criterion established in paragraph (d)(5)(ii) of this section, a leak is detected.
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Appendix: G-10

(6)(i) When a leak is detected pursuant to paragraph (d)(4)(ii)(A) of this section, it shall 

be repaired as specified in paragraph (c) of this section.

(ii) A leak detected pursuant to paragraph (d)(5)(iii) of this section shall be repaired 

within 15 days of detection by eliminating the conditions that activated the sensor.

(iii) A designated leak pursuant to paragraph (d)(4)(ii)(B) of this section shall be repaired 

within 15 days of detection by eliminating visual indications of liquids dripping.

(e) Any pump that is designated, as described in section G.8(e)(1) and (2), for no 

detectable emissions, as indicated by an instrument reading of less than 500 ppm above 

background, is exempt from the requirements of paragraphs (a), (c), and (d) of this section if the 

pump:

(1) Has no externally actuated shaft penetrating the pump housing;

(2) Is demonstrated to be operating with no detectable emissions as indicated by an 

instrument reading of less than 500 ppm above background as measured by the methods 

specified in section G.7(c); and

(3) Is tested for compliance with paragraph (e)(2) of this section initially upon 

designation, annually, and at other times requested by the permitting authority

(f) If any pump is equipped with a closed vent system capable of capturing and 

transporting any leakage from the seal or seals to a process or to a fuel gas system or to a control 

device that complies with the requirements of section G.5.10, it is exempt from paragraphs (a) 

through (e) of this section.

(g) Any pump that is designated, as described in section G.8(f)(1), as an unsafe-tomonitor pump is exempt from the monitoring and inspection requirements of paragraphs (a) and 

(d)(4) through (6) of this section if:
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Appendix: G-11

(1) The owner or operator of the pump demonstrates that the pump is unsafe-to-monitor 

because monitoring personnel would be exposed to an immediate danger as a consequence of 

complying with paragraph (a) of this section; and

(2) The owner or operator of the pump has a written plan that requires monitoring of the 

pump as frequently as practicable during safe-to-monitor times, but not more frequently than the 

periodic monitoring schedule otherwise applicable, and repair of the equipment according to the 

procedures in paragraph (c) of this section if a leak is detected.

(h) Any pump that is located within the boundary of an unmanned plant site is exempt 

from the weekly visual inspection requirement of paragraphs (a)(2) and (d)(4) of this section, and 

the daily requirements of paragraph (d)(5) of this section, provided that each pump is visually

inspected as often as practicable and at least monthly.

G.5.3 What Equipment Component VOC Emission Control Requirements Apply to 

Compressors?

(a) Each compressor shall be equipped with a seal system that includes a barrier fluid 

system and that prevents leakage of VOC to the atmosphere, except as provided in section 

G.5.1(c) and paragraphs (h), (i), and (j) of this section.

(b) Each compressor seal system as required in paragraph (a) of this section shall be:

(1) Operated with the barrier fluid at a pressure that is greater than the compressor 

stuffing box pressure; or

(2) Equipped with a barrier fluid system degassing reservoir that is routed to a process or 

fuel gas system or connected by a closed vent system to a control device that complies with the 

requirements of section G.5.10; or

(3) Equipped with a system that purges the barrier fluid into a process stream with zero 

VOC emissions to the atmosphere.
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Appendix: G-12

(c) The barrier fluid system shall be in heavy liquid service or shall not be in VOC 

service.

(d) Each barrier fluid system as described in paragraph (a) shall be equipped with a 

sensor that will detect failure of the seal system, barrier fluid system, or both.

(e)(1) Each sensor as required in paragraph (d) of this section shall be checked daily or 

shall be equipped with an audible alarm.

(2) The owner or operator shall determine, based on design considerations and operating 

experience, a criterion that indicates failure of the seal system, the barrier fluid system, or both.

(f) If the sensor indicates failure of the seal system, the barrier system, or both based on 

the criterion determined under paragraph (e)(2) of this section, a leak is detected.

(g)(1) When a leak is detected, it shall be repaired as soon as practicable, but not later 

than 15 calendar days after it is detected, except as provided in section G.5.9.

(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is 

detected.

(h) A compressor is exempt from the requirements of paragraphs (a) and (b) of this 

section, if it is equipped with a closed vent system to capture and transport leakage from the 

compressor drive shaft back to a process or fuel gas system or to a control device that complies 

with the requirements of section G.5.10, except as provided in paragraph (i) of this section.

(i) Any compressor that is designated, as described in section G.8(e)(1) and (2), for no 

detectable emissions, as indicated by an instrument reading of less than 500 ppm above 

background, is exempt from the requirements of paragraphs (a) through (h) of this section if the 

compressor:

(1) Is demonstrated to be operating with no detectable emissions, as indicated by an 

instrument reading of less than 500 ppm above background, as measured by the methods 

specified in section G.7(c); and
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Appendix: G-13

(2) Is tested for compliance with paragraph (i)(1) of this section initially upon 

designation, annually, and at other times requested by the permitting authority.

G.5.4 What Equipment Component VOC Emission Control Requirements Apply to 

Pressure Relief Devices in Gas/Vapor Service?

(a) Except during pressure releases, each pressure relief device in gas/vapor service shall 

be operated with no detectable emissions, as indicated by an instrument reading of less than 500 

ppm above background, as determined by the methods specified in section G.7(c).

(b)(1) After each pressure release, the pressure relief device shall be returned to a 

condition of no detectable emissions, as indicated by an instrument reading of less than 500 ppm 

above background, as soon as practicable, but no later than 5 calendar days after the pressure 

release, except as provided in section G.5.9.

(2) No later than 5 calendar days after the pressure release, the pressure relief device shall 

be monitored to confirm the conditions of no detectable emissions, as indicated by an instrument 

reading of less than 500 ppm above background, by the methods specified in section G.7(c).

(c) Any pressure relief device that is routed to a process or fuel gas system or equipped 

with a closed vent system capable of capturing and transporting leakage through the pressure 

relief device to a control device as described in section G.5.10 is exempted from the 

requirements of paragraphs (a) and (b) of this section.

(d)(1) Any pressure relief device that is equipped with a rupture disk upstream of the 

pressure relief device is exempt from the requirements of paragraphs (a) and (b) of this section, 

provided the owner or operator complies with the requirements in paragraph (d)(2) of this 

section.

(2) After each pressure release, a new rupture disk shall be installed upstream of the 

pressure relief device as soon as practicable, but no later than 5 calendar days after each pressure 

release, except as provided in section G.5.9.
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Appendix: G-14

G.9.5 What Equipment Component VOC Emission Control Requirements Apply to 

Sampling Connection Systems?

(a) Each sampling connection system shall be equipped with a closed-purge, closed-loop, 

or closed-vent system, except as provided in section G.5.1(c) and paragraph (c) of this section.

(b) Each closed-purge, closed-loop, or closed-vent system as required in paragraph (a) of 

this section shall comply with the requirements specified in paragraphs (b)(1) through (4) of this 

section.

(1) Gases displaced during filling of the sample container are not required to be collected 

or captured.

(2) Containers that are part of a closed-purge system must be covered or closed when not 

being filled or emptied.

(3) Gases remaining in the tubing or piping between the closed-purge system valve(s) and 

sample container valve(s) after the valves are closed and the sample container is disconnected are 

not required to be collected or captured.

(4) Each closed-purge, closed-loop, or closed-vent system shall be designed and operated 

to meet requirements in either paragraph (b)(4)(i), (ii), (iii), or (iv) of this section.

(i) Return the purged process fluid directly to the process line.

(ii) Collect and recycle the purged process fluid to a process.

(iii) Capture and transport all the purged process fluid to a control device that complies 

with the requirements of section G.5.10.

(iv) Collect, store, and transport the purged process fluid to any of the following systems 

or facilities:
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Appendix: G-15

(A) A waste management unit as defined in 40 CFR 63.111, if the waste management 

unit is subject to and operated in compliance with the provisions of 40 CFR part 63, subpart G, 

applicable to Group 1 wastewater streams;

(B) A treatment, storage, or disposal facility subject to regulation under 40 CFR part 262, 

264, 265, or 266;

(C) A facility permitted, licensed, or registered by a state to manage municipal or 

industrial solid waste, if the process fluids are not hazardous waste as defined in 40 CFR part 

261;

(D) A waste management unit subject to and operated in compliance with the treatment 

requirements of 40 CFR 61.348(a), provided all waste management units that collect, store, or 

transport the purged process fluid to the treatment unit are subject to and operated in compliance 

with the management requirements of 40 CFR 61.343 through 40 CFR 61.347; or

(E) A device used to burn off-specification used oil for energy recovery in accordance 

with 40 CFR part 279, subpart G, provided the purged process fluid is not hazardous waste as 

defined in 40 CFR part 261.

(c) In-situ sampling systems and sampling systems without purges are exempt from the 

requirements of paragraphs (a) and (b) of this section.

G.5.6 What Equipment Component VOC Emission Control Requirements Apply to OpenEnded Valves or Lines?

(a)(1) Each open-ended valve or line shall be equipped with a cap, blind flange, plug, or a 

second valve, except as provided in section G.5.1(c) and paragraphs (d) and (e) of this section.

(2) The cap, blind flange, plug, or second valve shall seal the open end at all times except 

during operations requiring process fluid flow through the open-ended valve or line.

(b) Each open-ended valve or line equipped with a second valve shall be operated in a 

manner such that the valve on the process fluid end is closed before the second valve is closed.
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Appendix: G-16

(c) When a double block-and-bleed system is being used, the bleed valve or line may

remain open during operations that require venting the line between the block valves but shall 

comply with paragraph (a) of this section at all other times.

(d) Open-ended valves or lines in an emergency shutdown system which are designed to 

open automatically in the event of a process upset are exempt from the requirements of 

paragraphs (a), (b), and (c) of this section.

(e) Open-ended valves or lines containing materials which would auto-catalytically 

polymerize or would present an explosion, serious overpressure, or other safety hazard if capped 

or equipped with a double block and bleed system as specified in paragraphs (a) through (c) of 

this section are exempt from the requirements of paragraphs (a) through (c) of this section.

G.5.7 What Equipment Component VOC Emission Control Requirements Apply to 

Valves in Gas/Vapor Service and in Light Liquid Service?

(a)(1) Each valve shall be monitored monthly to detect leaks by the methods specified in 

G.7(b) and shall comply with paragraphs (b) through (e) of this section, except as provided in 

paragraphs (f), (g), and (h) of this section, section G.5.1(c) and (f), and sections G.6.1 and G.6.2.

(2) A valve that begins operation in gas/vapor service or light liquid service after the 

compliance date for the process unit must be monitored according to paragraphs (a)(2)(i) or (ii), 

except for a valve that replaces a leaking valve and except as provided in paragraphs (f), (g), and 

(h) of this section, section G.5.1(c), and sections G.6.1 and G.6.2.

(i) Monitor the valve as in paragraph (a)(1) of this section. The valve must be monitored 

for the first time within 30 days after the end of its startup period to ensure proper installation.

(ii) If the existing valves in the process unit are monitored in accordance with section 

G.6.1 or section G.6.2, count the new valve as leaking when calculating the percentage of valves 

leaking as described in section G.6.2(b)(5). If less than 2.0 percent of the valves are leaking for 

that process unit, the valve must be monitored for the first time during the next scheduled 

monitoring event for existing valves in the process unit or within 90 days, whichever comes first.
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Appendix: G-17

(b) If an instrument reading of 500 ppm or greater is measured, a leak is detected.

(c)(1)(i) Any valve for which a leak is not detected for 2 successive months may be 

monitored the first month of every quarter, beginning with the next quarter, until a leak is 

detected.

(ii) As an alternative to monitoring all of the valves in the first month of a quarter, an 

owner or operator may elect to subdivide the process unit into two or three subgroups of valves 

and monitor each subgroup in a different month during the quarter, provided each subgroup is 

monitored every 3 months. The owner or operator must keep records of the valves assigned to 

each subgroup.

(2) If a leak is detected, the valve shall be monitored monthly until a leak is not detected 

for 2 successive months.

(d)(1) When a leak is detected, it shall be repaired as soon as practicable, but no later than 

15 calendar days after the leak is detected, except as provided in section G.5.9.

(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is 

detected.

(e) First attempts at repair include, but are not limited to, the following best practices 

where practicable:

(1) Tightening of bonnet bolts;

(2) Replacement of bonnet bolts;

(3) Tightening of packing gland nuts;

(4) Injection of lubricant into lubricated packing.

(f) Any valve that is designated, as described in section G.8(e)(2), for no detectable 

emissions, as indicated by an instrument reading of less than 500 ppm above background, is 

exempt from the requirements of paragraph (a) of this section if the valve:
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Appendix: G-18

(1) Has no external actuating mechanism in contact with the process fluid,

(2) Is operated with emissions less than 500 ppm above background as determined by the 

method specified in section G.7(c), and

(3) Is tested for compliance with paragraph (f)(2) of this section initially upon 

designation, annually, and at other times requested by the permitting authority.

(g) Any valve that is designated, as described in section G.8(f)(1), as an unsafe-tomonitor valve is exempt from the requirements of paragraph (a) of this section if:

(1) The owner or operator of the valve demonstrates that the valve is unsafe to monitor 

because monitoring personnel would be exposed to an immediate danger as a consequence of 

complying with paragraph (a) of this section, and

(2) The owner or operator of the valve adheres to a written plan that requires monitoring 

of the valve as frequently as practicable during safe-to-monitor times.

(h) Any valve that is designated, as described in section G.8(f)(2), as a difficult-tomonitor valve is exempt from the requirements of paragraph (a) of this section if:

(1) The owner or operator of the valve demonstrates that the valve cannot be monitored 

without elevating the monitoring personnel more than 2 meters above a support surface.

(2) The process unit within which the valve is located either has less than 3.0 percent of 

its total number of valves designated as difficult-to-monitor by the owner or operator.

(3) The owner or operator of the valve follows a written plan that requires monitoring of 

the valve at least once per calendar year.
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Appendix: G-19

G.5.8 What Equipment Component VOC Emission Control Requirements Apply to 

Pumps, Valves, and Connectors in Heavy Liquid Service and Pressure Relief Devices in 

Light Liquid or Heavy Liquid Service?

(a) If evidence of a potential leak is found by visual, audible, olfactory, or any other 

detection method at pumps, valves, and connectors in heavy liquid service and pressure relief 

devices in light liquid or heavy liquid service, the owner or operator shall follow either one of the 

following procedures:

(1) The owner or operator shall monitor the equipment within 5 days by the method 

specified in section G.7(b) and shall comply with the requirements of paragraphs (b) through (d) 

of this section.

(2) The owner or operator shall eliminate the visual, audible, olfactory, or other 

indication of a potential leak within 5 calendar days of detection.

(b) If an instrument reading of 10,000 ppm or greater is measured, a leak is detected.

(c)(1) When a leak is detected, it shall be repaired as soon as practicable, but not later 

than 15 calendar days after it is detected, except as provided in section G.5.9.

(2) The first attempt at repair shall be made no later than 5 calendar days after each leak 

is detected.

(d) First attempts at repair include, but are not limited to, the best practices described 

under sections G.5.2(c)(2) and G.5.7(e).

G.5.9 What Delay of Repair of Equipment Component Requirements Apply When 

Equipment Component Leaks Have Been Detected?

(a) Delay of repair of equipment for which leaks have been detected will be allowed if 

repair within 15 days is technically infeasible without a process unit shutdown. Repair of this 

equipment shall occur before the end of the next process unit shutdown. Monitoring to verify

repair must occur within 15 days after startup of the process unit.
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Appendix: G-20

(b) Delay of repair of equipment will be allowed for equipment which is isolated from the 

process and which does not remain in VOC service.

(c) Delay of repair for valves and connectors will be allowed if:

(1) The owner or operator demonstrates that emissions of purged material resulting from 

immediate repair are greater than the fugitive emissions likely to result from delay of repair, and

(2) When repair procedures are effected, the purged material is collected and destroyed or 

recovered in a control device complying with section G.5.10.

(d) Delay of repair for pumps will be allowed if:

(1) Repair requires the use of a dual mechanical seal system that includes a barrier fluid 

system, and

(2) Repair is completed as soon as practicable, but not later than 6 months after the leak 

was detected.

(e) Delay of repair beyond a process unit shutdown will be allowed for a valve, if valve 

assembly replacement is necessary during the process unit shutdown, valve assembly supplies 

have been depleted, and valve assembly supplies had been sufficiently stocked before the 

supplies were depleted. Delay of repair beyond the next process unit shutdown will not be 

allowed unless the next process unit shutdown occurs sooner than 6 months after the first process 

unit shutdown.

(f) When delay of repair is allowed for a leaking pump, valve, or connector that remains 

in service, the pump, valve, or connector may be considered to be repaired and no longer subject 

to delay of repair requirements if two consecutive monthly monitoring instrument readings are 

below the leak definition.
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Appendix: G-21

G.5.10 What VOC Emission Control Requirements Apply for Closed Vent Systems and 

Control Devices?

(a) Owners or operators of closed vent systems and control devices used to comply with 

provisions of this rule shall comply with the provisions of this section.

(b) Vapor recovery systems (for example, condensers and absorbers) shall be designed 

and operated to recover the VOC emissions vented to them with an efficiency of 95 percent or 

greater.

(c) Each enclosed combustion device (e.g., thermal vapor incinerator, catalytic vapor 

incinerator, boiler, or process heater) shall be designed to reduce the mass content of VOC 

emissions by 95 percent or greater in accordance with the requirements of section F(b).

(d) Flares used to comply with this subpart shall comply with the requirements of §60.18.

(e) Owners or operators of control devices used to comply with the provisions of this rule

shall monitor these control devices to ensure that they are operated and maintained in 

conformance with their designs.

(f) Except as provided in paragraphs (i) through (k) of this section, each closed vent 

system shall be inspected according to the procedures and schedule specified in paragraphs (f)(1) 

and (2) of this section.

(1) If the vapor collection system or closed vent system is constructed of hard-piping, the 

owner or operator shall comply with the requirements specified in paragraphs (f)(1)(i) and (ii) of 

this section:

(i) Conduct an initial inspection according to the procedures in section G.7 (b); and

(ii) Conduct annual visual inspections for visible, audible, or olfactory indications of 

leaks.
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Appendix: G-22

(2) If the vapor collection system or closed vent system is constructed of ductwork, the 

owner or operator shall:

(i) Conduct an initial inspection according to the procedures in section G.7(b); and

(ii) Conduct annual inspections according to the procedures in section G.7 (b).

(g) Leaks, as indicated by an instrument reading greater than 500 ppmv above 

background or by visual inspections, shall be repaired as soon as practicable except as provided 

in paragraph (h) of this section.

(1) A first attempt at repair shall be made no later than 5 calendar days after the leak is 

detected.

(2) Repair shall be completed no later than 15 calendar days after the leak is detected.

(h) Delay of repair of a closed vent system for which leaks have been detected is allowed 

if the repair is technically infeasible without a process unit shutdown or if the owner or operator 

determines that emissions resulting from immediate repair would be greater than the fugitive 

emissions likely to result from delay of repair. Repair of such equipment shall be complete by 

the end of the next process unit shutdown.

(i) If a vapor collection system or closed vent system is operated under a vacuum, it is 

exempt from the inspection requirements of paragraphs (f)(1)(i) and (f)(2) of this section.

(j) Any parts of the closed vent system that are designated, as described in paragraph 

(l)(1) of this section, as unsafe to inspect are exempt from the inspection requirements of 

paragraphs (f)(1)(i) and (f)(2) of this section if they comply with the requirements specified in 

paragraphs (j)(1) and (2) of this section:

(1) The owner or operator determines that the equipment is unsafe to inspect because 

inspecting personnel would be exposed to an imminent or potential danger as a consequence of 

complying with paragraphs (f)(1)(i) or (f)(2) of this section; and
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Appendix: G-23

(2) The owner or operator has a written plan that requires inspection of the equipment as 

frequently as practicable during safe-to-inspect times.

(k) Any parts of the closed vent system that are designated, as described in paragraph 

(l)(2) of this section, as difficult to inspect are exempt from the inspection requirements of 

paragraphs (f)(1)(i) and (f)(2) of this section if they comply with the requirements specified in 

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

(1) The owner or operator determines that the equipment cannot be inspected without 

elevating the inspecting personnel more than 2 meters above a support surface; and

(2) The owner or operator designates less than 3.0 percent of the total number of closed 

vent system equipment as difficult to inspect; and

(3) The owner or operator has a written plan that requires inspection of the equipment at 

least once every 5 years. A closed vent system is exempt from inspection if it is operated under a 

vacuum.

(l) The owner or operator shall record the information specified in paragraphs (l)(1) 

through (5) of this section.

(1) Identification of all parts of the closed vent system that are designated as unsafe to 

inspect, an explanation of why the equipment is unsafe to inspect, and the plan for inspecting the 

equipment.

(2) Identification of all parts of the closed vent system that are designated as difficult to 

inspect, an explanation of why the equipment is difficult to inspect, and the plan for inspecting 

the equipment.

(3) For each inspection during which a leak is detected, a record of the information 

specified in section G.8 (c).
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Appendix: G-24

(4) For each inspection conducted in accordance with section G.7 (b) during which no 

leaks are detected, a record that the inspection was performed, the date of the inspection, and a 

statement that no leaks were detected.

(5) For each visual inspection conducted in accordance with paragraph (f)(1)(ii) of this 

section during which no leaks are detected, a record that the inspection was performed, the date 

of the inspection, and a statement that no leaks were detected.

(m) Closed vent systems and control devices used to comply with provisions of this rule 

shall be operated at all times when emissions may be vented to them.

G.5.11 What VOC Emission Control Requirements Apply to Connectors in Gas/Vapor 

Service and in Light Liquid Service?

(a) The owner or operator shall initially monitor all connectors in the process unit for 

leaks by the later of either 12 months after the compliance date. If all connectors in the process 

unit have been monitored for leaks prior to the compliance date, no initial monitoring is required 

provided either no process changes have been made since the monitoring or the owner or 

operator can determine that the results of the monitoring, with or without adjustments, reliably

demonstrate compliance despite process changes. If required to monitor because of a process 

change, the owner or operator is required to monitor only those connectors involved in the 

process change.

(b) Except as allowed in sections G.5.1(c) and G.5.10, or as specified in paragraph (e) of 

this section, the owner or operator shall monitor all connectors in gas and vapor and light liquid 

service as specified in paragraphs (a) and (b)(3) of this section.

(1) The connectors shall be monitored to detect leaks by the method specified in section 

G.7 (b) and, as applicable, section G.7(c).

(2) If an instrument reading greater than or equal to 500 ppm is measured, a leak is 

detected.
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Appendix: G-25

(3) The owner or operator shall perform monitoring, subsequent to the initial monitoring 

required in paragraph (a) of this section, as specified in paragraphs (b)(3)(i) through (iii) of this 

section, and shall comply with the requirements of paragraphs (b)(3)(iv) and (v) of this section. 

The required period in which monitoring must be conducted shall be determined from 

paragraphs (b)(3)(i) through (iii) of this section using the monitoring results from the preceding 

monitoring period. The percent leaking connectors shall be calculated as specified in paragraph 

(c) of this section.

(i) If the percent leaking connectors in the process unit was greater than or equal to 0.5 

percent, then monitor within 12 months (1 year).

(ii) If the percent leaking connectors in the process unit was greater than or equal to 0.25 

percent but less than 0.5 percent, then monitor within 4 years. An owner or operator may comply

with the requirements of this paragraph by monitoring at least 40 percent of the connectors 

within 2 years of the start of the monitoring period, provided all connectors have been monitored 

by the end of the 4-year monitoring period.

(iii) If the percent leaking connectors in the process unit was less than 0.25 percent, then 

monitor as provided in paragraph (b)(3)(iii)(A) of this section and either paragraph (b)(3)(iii)(B) 

or (b)(3)(iii)(C) of this section, as appropriate.

(A) An owner or operator shall monitor at least 50 percent of the connectors within 4 

years of the start of the monitoring period.

(B) If the percent of leaking connectors calculated from the monitoring results in 

paragraph (b)(3)(iii)(A) of this section is greater than or equal to 0.35 percent of the monitored 

connectors, the owner or operator shall monitor as soon as practical, but within the next 6 

months, all connectors that have not yet been monitored during the monitoring period. At the 

conclusion of monitoring, a new monitoring period shall be started pursuant to paragraph (b)(3) 

of this section, based on the percent of leaking connectors within the total monitored connectors.

(C) If the percent of leaking connectors calculated from the monitoring results in 

paragraph (b)(3)(iii)(A) of this section is less than 0.35 percent of the monitored connectors, the 
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Appendix: G-26

owner or operator shall monitor all connectors that have not yet been monitored within 8 years of 

the start of the monitoring period.

(iv) If, during the monitoring conducted pursuant to paragraphs (b)(3)(i) through (iii) of 

this section, a connector is found to be leaking, it shall be re-monitored once within 90 days after 

repair to confirm that it is not leaking.

(v) The owner or operator shall keep a record of the start date and end date of each 

monitoring period under this section for each process unit.

(c) For use in determining the monitoring frequency, as specified in paragraphs (a) and 

(b)(3) of this section, the percent leaking connectors as used in paragraphs (a) and (b)(3) of this 

section shall be calculated by using the following equation:

%CL = CL / Ct * 100

Where:

%CL = Percent of leaking connectors as determined through periodic monitoring required 

in paragraphs (a) and (b)(3)(i) through (iii) of this section.

CL = Number of connectors measured at 500 ppm or greater, by the method specified in 

X.G.7(b).

Ct = Total number of monitored connectors in the process unit.

(d) When a leak is detected pursuant to paragraphs (a) and (b) of this section, it shall be 

repaired as soon as practicable, but not later than 15 calendar days after it is detected, except as 

provided in section G.5.9. A first attempt at repair as defined in this rule shall be made no later 

than 5 calendar days after the leak is detected.

(e) Any connector that is designated, as described in section G.8(f)(1), as an unsafe-tomonitor connector is exempt from the requirements of paragraphs (a) and (b) of this section if:
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Appendix: G-27

(1) The owner or operator of the connector demonstrates that the connector is unsafe-tomonitor because monitoring personnel would be exposed to an immediate danger as a 

consequence of complying with paragraphs (a) and (b) of this section; and

(2) The owner or operator of the connector has a written plan that requires monitoring of 

the connector as frequently as practicable during safe-to-monitor times, but not more frequently

than the periodic monitoring schedule otherwise applicable, and repair of the equipment 

according to the procedures in paragraph (d) of this section if a leak is detected.

(f) Inaccessible, ceramic, or ceramic-lined connectors. (1) Any connector that is 

inaccessible or that is ceramic or ceramic-lined (e.g., porcelain, glass, or glass-lined), is exempt 

from the monitoring requirements of paragraphs (a) and (b) of this section, from the leak repair 

requirements of paragraph (d) of this section, and from recordkeeping and reporting 

requirements. An inaccessible connector is one that meets any of the provisions specified in 

paragraphs (f)(1)(i) through (vi) of this section, as applicable:

(i) Buried;

(ii) Insulated in a manner that prevents access to the connector by a monitor probe;

(iii) Obstructed by equipment or piping that prevents access to the connector by a monitor 

probe;

(iv) Unable to be reached from a wheeled scissor-lift or hydraulic-type scaffold that 

would allow access to connectors up to 7.6 meters (25 feet) above the ground;

(v) Inaccessible because it would require elevating the monitoring personnel more than 2 

meters (7 feet) above a permanent support surface or would require the erection of scaffold; or

(vi) Not able to be accessed at any time in a safe manner to perform monitoring. Unsafe 

access includes, but is not limited to, the use of a wheeled scissor-lift on unstable or uneven 

terrain, the use of a motorized man-lift basket in areas where an ignition potential exists, or 

access would require near proximity to hazards such as electrical lines, or would risk damage to 

equipment.
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Appendix: G-28

(2) If any inaccessible, ceramic, or ceramic-lined connector is observed by visual, 

audible, olfactory, or other means to be leaking, the visual, audible, olfactory, or other 

indications of a leak to the atmosphere shall be eliminated as soon as practical.

(g) Except for instrumentation systems and inaccessible, ceramic, or ceramic-lined 

connectors meeting the provisions of paragraph (f) of this section, identify the connectors subject 

to the requirements of this rule. Connectors need not be individually identified if all connectors 

in a designated area or length of pipe subject to the provisions of this rule are identified as a 

group, and the number of connectors subject to the requirements is indicated.

G.6 Alternative Standards

G.6.1 Alternative Standards for Valves—Allowable Percentage of Valves Leaking

(a) An owner or operator may elect to comply with an allowable percentage of valves 

leaking of equal to or less than 2.0 percent.

(b) The following requirements shall be met if an owner or operator wishes to comply

with an allowable percentage of valves leaking:

(1) An owner or operator must notify the permitting authority that the owner or operator 

has elected to comply with the allowable percentage of valves leaking before implementing this 

alternative standard, as specified in section G.9(d).

(2) A performance test as specified in paragraph (c) of this section shall be conducted 

initially upon designation, annually, and at other times requested by the permitting authority.

(3) If a valve leak is detected, it shall be repaired in accordance with section G.5.7(d) and 

(e).

(c) Performance tests shall be conducted in the following manner:
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Appendix: G-29

(1) All valves in gas/vapor and light liquid service within the natural gas processing plant 

subject to VOC emission control requirements shall be monitored within 1 week by the methods 

specified in section G.7(b).

(2) If an instrument reading of 500 ppm or greater is measured, a leak is detected.

(3) The leak percentage shall be determined by dividing the number of valves for which 

leaks are detected by the number of valves in gas/vapor and light liquid service within the natural 

gas processing plant subject to VOC emission control requirements.

(d) Owners and operators who elect to comply with this alternative standard shall not 

have a natural gas processing plant subject to the equipment component VOC emission control

requirements with a leak percentage greater than 2.0 percent, determined as described in section 

G.7(h).

G.6.2 Alternative Standards for Valves—Skip Period Leak Detection and Repair

(a)(1) An owner or operator may elect to comply with one of the alternative work 

practices specified in paragraphs (b)(2) and (3) of this section.

(2) An owner or operator must notify the permitting authority before implementing one 

of the alternative work practices.

(b)(1) An owner or operator shall comply initially with the requirements for valves in 

gas/vapor service and valves in light liquid service, as described in section G.5.7.

(2) After 2 consecutive quarterly leak detection periods with the percent of valves leaking 

equal to or less than 2.0, an owner or operator may begin to skip 1 of the quarterly leak detection 

periods for the valves in gas/vapor and light liquid service.

(3) After 5 consecutive quarterly leak detection periods with the percent of valves leaking 

equal to or less than 2.0, an owner or operator may begin to skip 3 of the quarterly leak detection 

periods for the valves in gas/vapor and light liquid service.
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Appendix: G-30

(4) If the percent of valves leaking is greater than 2.0, the owner or operator shall comply

with the requirements as described in section G.5.7 but can again elect to use this section.

(5) The percent of valves leaking shall be determined as described in section G.7(h).

(6) An owner or operator must keep a record of the percent of valves found leaking 

during each leak detection period.

(7) A valve that begins operation in gas/vapor service or light liquid service after the 

compliance date for a process unit following one of the alternative standards in this section must 

be monitored in accordance with section G.5.7(a)(2)(i) or (ii) before the provisions of this section 

can be applied to that valve.

G.7 Equipment Leak Test Methods and Procedures

(a) In conducting the performance tests, the owner or operator shall use as reference 

methods and procedures the test methods in appendix A of this part or other methods and 

procedures as specified in this section.

(b) The owner or operator shall determine compliance with the standards in sections 

G.5.1 through G.5.11, and as follows:

(1) USEPA Method 21 shall be used to determine the presence of leaking sources. The 

instrument shall be calibrated before use each day of its use by the procedures specified in 

USEPA Method 21 of appendix A-7 of this part. The following calibration gases shall be used:

(i) Zero air (less than 10 ppm of hydrocarbon in air); and

(ii) A mixture of methane or n-hexane and air at a concentration no more than 2,000 ppm 

greater than the leak definition concentration of the equipment monitored. If the monitoring 

instrument's design allows for multiple calibration scales, then the lower scale shall be calibrated 

with a calibration gas that is no higher than 2,000 ppm above the concentration specified as a 

leak, and the highest scale shall be calibrated with a calibration gas that is approximately equal to 
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Appendix: G-31

10,000 ppm. If only one scale on an instrument will be used during monitoring, the owner or 

operator need not calibrate the scales that will not be used during that day's monitoring.

(2) A calibration drift assessment shall be performed, at a minimum, at the end of each 

monitoring day. Check the instrument using the same calibration gas(es) that were used to 

calibrate the instrument before use. Follow the procedures specified in USEPA Method 21 of 

appendix A-7 of this part, Section 10.1, except do not adjust the meter readout to correspond to 

the calibration gas value. Record the instrument reading for each scale used as specified in 

section G.8(e)(7). Calculate the average algebraic difference between the three meter readings 

and the most recent calibration value. Divide this algebraic difference by the initial calibration 

value and multiply by 100 to express the calibration drift as a percentage. If any calibration drift 

assessment shows a negative drift of more than 10 percent from the initial calibration value, then 

all equipment monitored since the last calibration with instrument readings below the appropriate 

leak definition and above the leak definition multiplied by (100 minus the percent of negative 

drift/divided by 100) must be re-monitored. If any calibration drift assessment shows a positive 

drift of more than 10 percent from the initial calibration value, then, at the owner/operator's 

discretion, all equipment since the last calibration with instrument readings above the appropriate 

leak definition and below the leak definition multiplied by (100 plus the percent of positive 

drift/divided by 100) may be re-monitored.

(c) The owner or operator shall determine compliance with the no-detectable-emission 

standards in sections G.5.2(e), G.5.3(i), G.5.4, G.5.7(f), and G.5.10(e) as follows:

(1) The requirements of paragraph (b) shall apply.

(2) USEPA Method 21 of appendix A-7 of this part shall be used to determine the 

background level. All potential leak interfaces shall be traversed as close to the interface as 

possible. The arithmetic difference between the maximum concentration indicated by the 

instrument and the background level is compared with 500 ppm for determining compliance.

(d) The owner or operator shall test each piece of equipment unless he demonstrates that 

a process unit is not in VOC service, i.e., that the VOC content would never be reasonably 
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Appendix: G-32

expected to exceed 10 percent by weight. For purposes of this demonstration, the following 

methods and procedures shall be used:

(1) Procedures that conform to the general methods in ASTM E260-73, 91, or 96, E168-

67, 77, or 92, E169-63, 77, or 93 shall be used to determine the percent VOC content in the 

process fluid that is contained in or contacts a piece of equipment.

(2) Organic compounds that are considered by the permitting authority to have negligible 

photochemical reactivity may be excluded from the total quantity of organic compounds in 

determining the VOC content of the process fluid.

(3) Engineering judgment may be used to estimate the VOC content, if a piece of 

equipment had not been shown previously to be in service. If the permitting authority disagrees 

with the judgment, paragraphs (d)(1) and (2) of this section shall be used to resolve the 

disagreement.

(e) The owner or operator shall demonstrate that a piece of equipment is in light liquid 

service by showing that all the following conditions apply:

(1) The vapor pressure of one or more of the organic components is greater than 0.3 kPa 

at 20 °C (1.2 in. H2O at 68 °F). Standard reference texts or ASTM D2879-83, 96, or 97 shall be 

used to determine the vapor pressures.

(2) The total concentration of the pure organic components having a vapor pressure 

greater than 0.3 kPa at 20 °C (1.2 in. H2O at 68 °F) is equal to or greater than 20 percent by 

weight.

(3) The fluid is a liquid at operating conditions.

(f) Samples used in conjunction with paragraphs (d), (e), and (g) of this section shall be 

representative of the process fluid that is contained in or contacts the equipment or the gas being 

combusted in the flare.
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Appendix: G-33

(g) The owner or operator shall determine compliance with the standards of flares as 

follows:

1) USEPA Method 22 of appendix A-7 of this part shall be used to determine visible 

emissions.

(2) A thermocouple or any other equivalent device shall be used to monitor the presence 

of a pilot flame in the flare.

(3) The maximum permitted velocity for air assisted flares shall be computed using the 

following equation:

Vmax = K1 + K2HT

Where:

Vmax = Maximum permitted velocity, m/sec (ft/sec).

HT = Net heating value of the gas being combusted, MJ/scm (Btu/scf).

K1 = 8.706 m/sec (metric units) = 28.56 ft/sec (English units).

K2 = 0.7084 m4/(MJ-sec) (metric units) = 0.087 ft4/(Btu-sec) (English units).

(4) The net heating value (HT) of the gas being combusted in a flare shall be computed 

using the following equation:

 = 





Where:

K = Conversion constant, 1.740×10−7(g-mole)(MJ)/(ppm-scm-kcal) (metric units) = 

4.674×10−6[(g-mole)(Btu)/(ppm-scf-kcal)] (English units).

Ci = Concentration of sample component “i,” ppm 
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Appendix: G-34

Hi = net heat of combustion of sample component “i” at 25°C and 760 mm Hg (77°F and 

14.7 psi), kcal/g-mole.

(5) USEPA Method 18 of appendix A-6 of this part or ASTM D6420-99 (2004) (where 

the target compound(s) are those listed in Section 1.1 of ASTM D6420-99, and the target 

concentration is between 150 parts per billion by volume and 100 ppmv) and ASTM D2504-67, 

77, or 88 (Reapproved 1993) shall be used to determine the concentration of sample component 

“i.”

(6) ASTM D2382-76 or 88 or D4809-95 shall be used to determine the net heat of 

combustion of component “i” if published values are not available or cannot be calculated.

(7) USEPA Method 2, 2A, 2C, or 2D of appendix A-7 of this part, as appropriate, shall be 

used to determine the actual exit velocity of a flare. If needed, the unobstructed (free) crosssectional area of the flare tip shall be used.

(h) The owner or operator shall determine compliance with section G.6.1 or section G.6.2 

as follows:

(1) The percent of valves leaking shall be determined using the following equation:

%VL = (VL / VT) * 100

Where:

%VL = Percent leaking valves.

VL = Number of valves found leaking.

VT = The sum of the total number of valves monitored.

(2) The total number of valves monitored shall include difficult-to-monitor and unsafe-tomonitor valves only during the monitoring period in which those valves are monitored.

(3) The number of valves leaking shall include valves for which repair has been delayed.
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Appendix: G-35

(4) Any new valve that is not monitored within 30 days of being placed in service shall 

be included in the number of valves leaking and the total number of valves monitored for the 

monitoring period in which the valve is placed in service.

(5) If the process unit has been subdivided in accordance with section G.5.7(c)(1)(ii), the 

sum of valves found leaking during a monitoring period includes all subgroups.

(6) The total number of valves monitored does not include a valve monitored to verify

repair.

(i) When each leak is detected as specified in sections G.5.2, G.5.3, G.5.7, G.5.8, G.5.11, 

and G.6.2, the following requirements apply:

(1) A weatherproof and readily visible identification, marked with the equipment 

identification number, shall be attached to the leaking equipment.

(2) The identification on a valve may be removed after it has been monitored for 2 

successive months as specified in section G.5.7(c) and no leak has been detected during those 2 

months.

(3) The identification on a connector may be removed after it has been monitored as 

specified in section G.9.7(b)(3)(iv) and no leak has been detected during that monitoring.

(4) The identification on equipment, except on a valve or connector, may be removed 

after it has been repaired.

G.8 Recordkeeping and Reporting Requirements

(a) Recordkeeping requirements. Each owner or operator subject to the VOC equipment 

leak requirements specified in section G shall maintain the records specified in paragraphs (a)(1) 

through (10), as applicable, onsite or at the nearest local field office for at least five years.
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Appendix: G-36

(1) An owner or operator of more than one facility subject to the requirements of section 

G may comply with the recordkeeping requirements for these facilities in one recordkeeping 

system if the system identifies each record by each facility.

(2) The owner or operator shall record the information specified in paragraphs (a)(2)(i) 

through (v) of this section for each monitoring event required by sections G.5.2, G.5.3, G.5.7, 

G.5.8, G.5.11, and G.6.2.

(i) Monitoring instrument identification.

(ii) Operator identification.

(iii) Equipment identification.

(iv) Date of monitoring.

(v) Instrument reading.

(3) When each leak is detected as specified in sections G.5.2, G.5.3, G.5.7, G.5.8, G.5.11, 

and G.6.2, the following information shall be recorded in a log and shall be kept for 2 years in a 

readily accessible location:

(i) The instrument and operator identification numbers and the equipment identification 

number, except when indications of liquids dripping from a pump are designated as a leak.

(ii) The date the leak was detected and the dates of each attempt to repair the leak.

(iii) Repair methods applied in each attempt to repair the leak.

(iv) Maximum instrument reading measured by USEPA Method 21 of appendix A-7 of 

this part at the time the leak is successfully repaired or determined to be non-repairable, except 

when a pump is repaired by eliminating indications of liquids dripping.

(v) “Repair delayed” and the reason for the delay if a leak is not repaired within 15 

calendar days after discovery of the leak.
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Appendix: G-37

(vi) The signature of the owner or operator (or designate) whose decision it was that 

repair could not be effected without a process shutdown.

(vii) The expected date of successful repair of the leak if a leak is not repaired within 15 

days.

(viii) Dates of process unit shutdowns that occur while the equipment is unrepaired.

(ix) The date of successful repair of the leak.

(4) The following information pertaining to the design requirements for closed vent 

systems and control devices described in section G.5.10 shall be recorded and kept in a readily

accessible location:

(i) Detailed schematics, design specifications, and piping and instrumentation diagrams.

(ii) The dates and descriptions of any changes in the design specifications.

(iii) A description of the parameter or parameters monitored, as required in section 

G.5.10(e), to ensure that control devices are operated and maintained in conformance with their 

design and an explanation of why that parameter (or parameters) was selected for the monitoring.

(iv) Periods when the closed vent systems and control devices required in sections G.5.2, 

G.5.3, G.5.4, and G.5.5 are not operated as designed, including periods when a flare pilot light 

does not have a flame.

(v) Dates of startups and shutdowns of the closed vent systems and control devices 

required in sections G.5.2, G.5.3, G.5.4, and G.5.5.

(5) The following information pertaining to all equipment subject to the requirements in 

sections G.5.1 to G.5.11 shall be recorded in a log that is kept in a readily accessible location:

(i) A list of identification numbers for equipment subject to the requirements of this rule.
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Appendix: G-38

(ii)(A) A list of identification numbers for equipment that are designated for no 

detectable emissions under the provisions of sections G.5.2(e), G.5.3(i), and G.5.7(f).

(B) The designation of equipment as subject to the requirements of sections G.5.2(e), 

G.5.3(i), or section G.5.7(f) shall be signed by the owner or operator. Alternatively, the owner or 

operator may establish a mechanism with their permitting authority that satisfies this 

requirement.

(C) A list of equipment identification numbers for pressure relief devices required to 

comply with section G.5.4.

(iii)(A) The dates of each compliance test as required in sections G.5.2(e), G.5.3(i), 

G.5.4, and G.5.7(f).

(B) The background level measured during each compliance test.

(C) The maximum instrument reading measured at the equipment during each 

compliance test.

(iv) A list of identification numbers for equipment in vacuum service.

(v) A list of identification numbers for equipment that the owner or operator designates as 

operating in VOC service less than 300 hr/yr in accordance with section G.5.1(e), a description 

of the conditions under which the equipment is in VOC service, and rationale supporting the 

designation that it is in VOC service less than 300 hr/yr.

(vi) The date and results of the weekly visual inspection for indications of liquids 

dripping from pumps in light liquid service.

(vii) Records of the information specified in paragraphs (a)(5)(vii)(A) through (F) of this 

section for monitoring instrument calibrations conducted according to sections 8.1.2 and 10 of 

USEPA Method 21 of appendix A-7 of this part and section G.7(b).

(A) Date of calibration and initials of operator performing the calibration.
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Appendix: G-39

(B) Calibration gas cylinder identification, certification date, and certified concentration.

(C) Instrument scale(s) used.

(D) A description of any corrective action taken if the meter readout could not be 

adjusted to correspond to the calibration gas value in accordance with section 10.1 of USEPA 

Method 21 of appendix A-7 of this part.

(E) Results of each calibration drift assessment required by section G.7(b)(2) (i.e., 

instrument reading for calibration at end of monitoring day and the calculated percent difference 

from the initial calibration value).

(F) If an owner or operator makes their own calibration gas, a description of the 

procedure used.

(viii) The connector monitoring schedule for each process unit as specified in section 

G.9.7(b)(3)(v).

(ix) Records of each release from a pressure relief device subject to section G.5.4.

(6) The following information pertaining to all valves subject to the requirements of 

section G.5.7(g) and (h), all pumps subject to the requirements of section G.5.2(g), and all 

connectors subject to the requirements of section G.5.11(e) shall be recorded in a log that is kept 

in a readily accessible location:

(i) A list of identification numbers for valves, pumps, and connectors that are designated 

as unsafe-to-monitor, an explanation for each valve, pump, or connector stating why the valve, 

pump, or connector is unsafe-to-monitor, and the plan for monitoring each valve, pump, or 

connector.

(ii) A list of identification numbers for valves that are designated as difficult-to-monitor, 

an explanation for each valve stating why the valve is difficult-to-monitor, and the schedule for 

monitoring each valve.
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Appendix: G-40

(7) The following information shall be recorded for valves complying with section G.6.2:

(i) A schedule of monitoring.

(ii) The percent of valves found leaking during each monitoring period.

(8) The following information shall be recorded in a log that is kept in a readily

accessible location:

(i) Design criterion required in sections G.5.2(d)(5) and G.5.3(e)(2) and explanation of 

the design criterion; and

(ii) Any changes to this criterion and the reasons for the changes.

(A) The following information shall be recorded in a log that is kept in a readily

accessible location for use in determining exemptions:

(1) An analysis demonstrating the design capacity of the natural gas processing plant,

(2) A statement listing the feed or raw materials and products from the processing 

plant(s) and an analysis demonstrating whether these chemicals are heavy liquids or beverage 

alcohol, and

(3) An analysis demonstrating that equipment is not in VOC service.

(9) Information and data used to demonstrate that a piece of equipment is not in VOC 

service shall be recorded in a log that is kept in a readily accessible location.

(10) The following recordkeeping requirements apply to pressure relief devices.

(i) When each leak is detected, a weatherproof and readily visible identification, marked 

with the equipment identification number, must be attached to the leaking equipment. The 

identification on the pressure relief device may be removed after it has been repaired.
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Appendix: G-41

(ii) When each leak is detected as specified in section G.3(b)(2), the following 

information must be recorded in a log and shall be kept for 2 years in a readily accessible 

location:

(A) The instrument and operator identification numbers and the equipment identification 

number.

(B) The date the leak was detected and the dates of each attempt to repair the leak.

(C) Repair methods applied in each attempt to repair the leak.

(D) “Above 500 ppm” if the maximum instrument reading measured by the methods 

specified in paragraph (a) of this section after each repair attempt is 500 ppm or greater.

(E) “Repair delayed” and the reason for the delay if a leak is not repaired within 15 

calendar days after discovery of the leak.

(F) The signature of the owner or operator (or designate) whose decision it was that 

repair could not be effected without a process shutdown.

(G) The expected date of successful repair of the leak if a leak is not repaired within 15 

days.

(H) Dates of process unit shutdowns that occur while the equipment is unrepaired.

(I) The date of successful repair of the leak.

(J) A list of identification numbers for equipment that are designated for no detectable 

emissions under the provisions of section G.5.4 (a). The designation of equipment subject to the 

provisions of section G.5.4 (a) must be signed by the owner or operator.

(b) Reporting requirements. Each owner or operator subject to the VOC equipment leak 

requirements shall comply with the reporting requirements of paragraphs (b)(1) through (5).
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Appendix: G-42

(1) Each owner or operator subject to the equipment leak VOC emission control 

requirements of section G.5 shall submit semiannual reports to the permitting authority 

beginning 6 months after a facility becomes subject to VOC emission control requirements of 

section G.

(2) The initial semiannual report to the permitting authority shall include the following 

information:

(i) Process unit identification.

(ii) Number of valves subject to the requirements of section G.5.7, excluding those valves 

designated for no detectable emissions under the provisions of section G.5.7(f).

(iii) Number of pumps subject to the requirements of section G.5.2, excluding those 

pumps designated for no detectable emissions under the provisions of section G.5.2(e) and those 

pumps complying with section G.5.2(f).

(iv) Number of compressors subject to the requirements of section G.5.3, excluding those 

compressors designated for no detectable emissions under the provisions of section G.5.3(i) and 

those compressors complying with section G.5.3(h).

(v) Number of connectors subject to the requirements of section G.9.11.

(vi) Number of pressure relief devices subject to the requirements, except for those 

pressure relief devices designated for no detectable emissions under the provisions of section 

G.5.4 (a) and those pressure relief devices complying with section G.5.4 (c).

(3) All semiannual reports to the permitting authority shall include the following 

information:

(i) Process unit identification.

(ii) For each month during the semiannual reporting period,
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Appendix: G-43

(A) Number of valves for which leaks were detected as described in section G.5.7(b) or 

section G.6.2,

(B) Number of valves for which leaks were not repaired as required in section 

G.5.7(d)(1),

(C) Number of pumps for which leaks were detected as described in section G.5.2(b), 

(d)(4)(ii)(A) or (B), or (d)(5)(iii),

(D) Number of pumps for which leaks were not repaired as required in section 

G.5.2(c)(1) and (d)(6),

(E) Number of compressors for which leaks were detected as described in section 

G.5.3(f),

(F) Number of compressors for which leaks were not repaired as required in section 

G.5.3(g)(1),

(G) Number of connectors for which leaks were detected as described in section G.9.7(b)

(H) Number of connectors for which leaks were not repaired as required in section 

G.9.7(d), and

(I) The facts that explain each delay of repair and, where appropriate, why a process unit 

shutdown was technically infeasible.

(iii) An owner or operator must include the following information in all semiannual 

reports:

(A) Number of pressure relief devices for which leaks were detected; and

(B) Number of pressure relief devices for which leaks were not repaired.

(iv) Dates of process unit shutdowns which occurred within the semiannual reporting 

period.
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Appendix: G-44

(v) Revisions to items reported according to paragraph (b)(1) of this section if changes 

have occurred since the initial report or subsequent revisions to the initial report.

(4) An owner or operator electing to comply with the provisions of section G.6.1 or 

section G.6.2 shall notify the permitting authority of the alternative standard selected 90 days 

before implementing either of the provisions.

(5) An owner or operator shall report the results of all performance tests to the permitting 

authority. 

G.9 Definitions

Equipment, as used in the standards and requirements in this rule relative to the 

equipment leaks of VOC from onshore natural gas processing plants, means each pump, pressure 

relief device, open-ended valve or line, valve, and flange or other connector that is in VOC 

service or in wet gas service, and any device or system required by those same standards and 

requirements in this rule.

Gas processing plant process unit means equipment assembled for the extraction of 

natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or 

other operations associated with the processing of natural gas products. A process unit can 

operate independently if supplied with sufficient feed or raw materials and sufficient storage 

facilities for the products.

Natural gas processing plant (gas plant) means any processing site engaged in the 

extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to 

natural gas products, or both. A Joule-Thompson valve, a dew point depression valve, or an 

isolated or standalone Joule-Thompson skid is not a natural gas processing plant.

Onshore means all facilities except those that are located in the territorial seas or on the 

outer continental shelf.
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H Pneumatic Pumps: VOC Emissions Control Requirements

H.1 Applicability 

Each pneumatic pump, which is a natural gas-driven chemical/methanol or natural gasdriven diaphragm pump located at a natural gas processing plant or located from the wellhead 

and point of custody transfer to the natural gas transmission and storage segment for which a 

control device is located on site. For purposes of the requirements specified in this section, we 

refer to these pumps as gas-driven pneumatic pumps.

H.2 What VOC Emission Reduction Requirements Apply to Natural GasDriven Pneumatic Pumps?

For each natural gas-driven pneumatic pump, you must comply with the VOC emission 

control requirements, based on natural gas as a surrogate for VOC, in either paragraph (a)(1) or 

(b)(1) of this section, as applicable. 

(a)(1) Each natural gas-driven pneumatic pump at a natural gas processing plant must 

have a natural gas emission rate of zero.

(2) Each natural gas-driven pneumatic pump at a natural gas processing plant must be 

tagged with the date the natural gas-driven pneumatic pump is required to comply with the 

model rule (as established by the regulatory authority) that allows traceability to the records for 

that gas-driven pneumatic pump as required in section H.5(a)(1)(i).

(b)(1) Each natural gas-driven pneumatic pump located between the wellhead and point 

of custody transfer to the natural gas transmission and storage segment, for which a control 

device is located on site, must reduce natural gas emissions by 95 percent, except as provided in 

paragraph (b)(2) of this section.

(2) You are not required to install a control device solely for the purposes of complying 

with the 95 percent reduction of paragraph (b)(1) of this section. If you do not have a control 
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Appendix: H-2

device installed on site by the compliance date specified by your regulatory authority, then you 

must comply instead with the provisions of paragraph (b)(2)(i) and (ii) of this section.

(i) Submit a certification in accordance with H.5(b)(1)(i).

(ii) If you subsequently install a control device, you are no longer required to submit the 

certification in H.5(b)(1)(i) and must be in compliance with the requirements of paragraph (b)(1) 

of this section within 30 days of installation of the control device. Compliance with this 

requirement should be reported in the next annual report in accordance with H.5(a)(1)(iii).

(3) Each natural gas-driven pneumatic pump located between the wellhead and point of 

custody transfer to the natural gas transmission and storage segment for which a control device is 

located on site must be tagged with the date that the pneumatic pump must comply with the 

model rule (as established by the regulatory authority) that allows traceability to the records for 

that natural gas-driven pneumatic pump as required in section H.5(a)(1)(ii).

(4) If you use a control device to reduce emissions, you must connect the natural gasdriven pneumatic pump subject to VOC emission control requirements through a closed vent 

system that meets the requirements of section D.1(b) and routed to a control device that meets 

the conditions specified in section E.1. As an alternative to routing the closed vent system to a 

control device, you may route the closed vent system to a process.

(c) You must demonstrate initial compliance by the compliance date specified by your 

regulatory authority by demonstrating compliance with standards that apply to natural gas-driven

pneumatic pump sources subject to VOC emission requirements as required by section H.3.

(d) You must demonstrate continuous compliance with standards that apply to natural 

gas-driven pneumatic pump sources subject to VOC emission requirements as required by

section H.4.

(e) You must perform the required recordkeeping, and reporting as required by section 

H.5.
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Appendix: H-3

H.3 Initial Compliance Demonstration Requirements

You must demonstrate initial compliance by the compliance date specified by your 

regulatory authority by demonstrating compliance with the VOC emission control requirements 

for natural gas-driven pneumatic pumps specified in paragraphs (a) through (f) of this section, as 

applicable.

(a) You own or operate a pneumatic pump located at a natural gas processing plant and 

your natural gas-driven chemical/methanol or diaphragm pump is driven by a gas other than 

natural gas and therefore emits zero natural gas.

(b) You own or operate a natural gas-driven pneumatic pump located between the 

wellhead and point of custody transfer to the natural gas transmission and storage segment and 

your natural gas-driven pneumatic pump is controlled by at least 95 percent.

(c) You own or operate a natural gas-driven pneumatic pump located between the 

wellhead and point of custody transfer to the natural gas transmission and storage segment and 

your pneumatic pump is not controlled by at least 95 percent because a control device is not 

available at the site, you must submit the certification in section H.5(a)(1)(i).

(d) You must tag each natural gas-driven pneumatic pump subject to VOC emission 

requirements according to the requirements of section (a)(2) or (b)(3), as applicable.

(e) You must include a listing of the natural gas-driven pneumatic pumps subject to VOC 

emission requirements specified in paragraphs (a) through (c) of this section in the initial annual 

report submitted for your natural gas-driven pneumatic pump according to the requirements of 

section H.5(b).

(f) You must maintain the records as specified in section H.5(a) for each natural gasdriven chemical/methanol or diaphragm pump subject to VOC emission control requirements of 

section H.
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Appendix: H-4

H.4 Continuous Compliance Demonstration Requirements

You have demonstrated continuous compliance for each natural gas-driven pneumatic

pump at a location with a control device on site by complying with the requirements of 

paragraphs (a) and (b) of this section.

(a) You must reduce VOC emissions from the natural gas-driven pneumatic pump by 95

percent or greater.

(b) For each control device used to reduce emissions, you must demonstrate continuous 

compliance with the performance requirements of section H.2(a)(1) and (b)(1) using the 

procedures specified in paragraphs (b)(1) through (7) of this section. If you use a condenser as 

the control device to achieve the requirements specified in section H.2, you must demonstrate 

compliance according to paragraph (b)(8) of this section. You may switch between compliance 

with paragraphs (b)(1) through (7) of this section and compliance with paragraph (b)(8) of this 

section only after at least 1 year of operation in compliance with the selected approach. You 

must provide notification of such a change in the compliance method in the next annual report, 

as required in section H.5(b)(1), following the change.

(1) You must operate below (or above) the site specific maximum (or minimum) 

parameter value established according to the requirements of section E.2(f)(1).

(2) You must calculate the daily average of the applicable monitored parameter in 

accordance with section E.2(e) except that the inlet gas flow rate to the control device must not 

be averaged.

(3) Compliance with the operating parameter limit is achieved when the daily average of 

the monitoring parameter value calculated under paragraph (b)(2) of this section is either equal to 

or greater than the minimum monitoring value or equal to or less than the maximum monitoring 

value established under paragraph (b)(1) of this section. When performance testing of a 

combustion control device is conducted by the device manufacturer as specified in section F(d), 

compliance with the operating parameter limit is achieved when the criteria in section F(e) are 

met.
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Appendix: H-5

(4) You must operate the continuous monitoring system required in section E.2(a) at all 

times the source is operating, except for periods of monitoring system malfunctions, repairs 

associated with monitoring system malfunctions, and required monitoring system quality 

assurance or quality control activities (including, as applicable, system accuracy audits and 

required zero and span adjustments). A monitoring system malfunction is any sudden, 

infrequent, not reasonably preventable failure of the monitoring system to provide valid data. 

Monitoring system failures that are caused in part by poor maintenance or careless operation are 

not malfunctions. You are required to complete monitoring system repairs in response to 

monitoring system malfunctions and to return the monitoring system to operation as 

expeditiously as practicable.

(5) You may not use data recorded during monitoring system malfunctions, repairs 

associated with monitoring system malfunctions, or required monitoring system quality 

assurance or control activities in calculations used to report emissions or operating levels. You 

must use all the data collected during all other required data collection periods to assess the 

operation of the control device and associated control system.

(6) Failure to collect required data is a deviation of the monitoring requirements, except 

for periods of monitoring system malfunctions, repairs associated with monitoring system 

malfunctions, and required quality monitoring system quality assurance or quality control 

activities (including, as applicable, system accuracy audits and required zero and span 

adjustments).

(7) If you use a combustion control device to meet the requirements of section H.2 and 

you demonstrate compliance using the test procedures specified in section F(b), you must 

comply with paragraphs (b)(7)(i) through (iv) of this section.

(i) A pilot flame must be present at all times of operation.

(ii) Devices must be operated with no visible emissions, except for periods not to exceed 

a total of one minute during any 15 minute period. A visible emissions test using section 11 of 

Method 22, 40 CFR part 60, appendix A, must be performed at least once every calendar month, 

separated by at least 15 days between each test. The observation period shall be 15 minutes. 
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Appendix: H-6

(iii) Devices failing the visible emissions test must follow manufacturer's repair 

instructions, if available, or best combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant operation. All repairs and 

maintenance activities for each unit must be recorded in a maintenance and repair log and must 

be available for inspection. 

(iv) Following return to operation from maintenance or repair activity, each device must 

pass a Method 22, 40 CFR part 60, appendix A, visual observation as described in paragraph 

(b)(7)(ii) of this section.

(8) If you use a condenser as the control device to achieve the percent reduction 

performance requirements specified in section H.2(b)(1), you must demonstrate compliance 

using the procedures in paragraphs (b)(8)(i) through (v) of this section.

(i) You must establish a site-specific condenser performance curve according to section 

E.2(f)(2).

(ii) You must calculate the daily average condenser outlet temperature in accordance with 

section E.2(e).

(iii) You must determine the condenser efficiency for the current operating day using the 

daily average condenser outlet temperature calculated under paragraph (b)(8)(ii) of this section 

and the condenser performance curve established under paragraph (b)(8)(i) of this section.

(D) Except as provided in paragraphs (b)(8)(iv)(A) and (B) of this section, at the end of 

each operating day, you must calculate the 365-day rolling average TOC emission reduction, as 

appropriate, from the condenser efficiencies as determined in paragraph (b)(8)(iii) of this section.

(A) After the compliance dates specified by your regulatory authority, if you have less 

than 120 days of data for determining average TOC emission reduction, you must calculate the 

average TOC emission reduction for the first 120 days of operation after the compliance date.

You have demonstrated compliance with the overall 95 percent reduction requirement if the 120-

day average TOC emission reduction is equal to or greater than 95 percent.
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Appendix: H-7

(B) After 120 days and no more than 364 days of operation after the compliance date 

specified by your regulatory authority, you must calculate the average TOC emission reduction 

as the TOC emission reduction averaged over the number of days between the current day and 

the applicable compliance date. You have demonstrated compliance with the overall 95 percent 

reduction requirement if the average TOC emission reduction is equal to or greater than 95 

percent.

(v) If you have data for 365 days or more of operation, you have demonstrated 

compliance with the TOC emission reduction if the rolling 365-day average TOC emission 

reduction calculated in paragraph (b)(8)(iv) of this section is equal to or greater than 95 percent.

(3) You must submit the annual report required by section H.5(b)(1) and maintain the 

records as specified in section H.5(a)(1).

H.5 Recordkeeping and Reporting Requirements

(a) Recordkeeping requirements. 

(1) For each applicable natural gas-driven pneumatic pump subject to VOC emission 

control requirements, you must maintain the records identified in paragraphs (a)(1)(i) through

(iii) of this section onsite or at the nearest local field office for at least five years.

(i) Records of the date that an individual natural gas-driven pneumatic pump is required 

to comply with the model rule (as specified by the regulatory authority), location and 

manufacturer specifications for each natural gas-driven pneumatic pump.

(ii) Records of deviations in cases where the natural gas-driven pneumatic pump was not 

operated in compliance with the requirements specified in section H.2.

(iii) Records of the control device installation date and the location of sites containing 

natural gas-driven pneumatic pumps at which a control device was installed, where previously 

there was no control device at the site.
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Appendix: H-8

(iv) Except as specified in paragraph (a)(iv)(G) of this section, records of each control 

device tested under section F(d) which meets the criteria in section F(d)(11) and section F(e) and 

used to comply with section H.2(b)(1) for each natural gas-driven pneumatic pump. 

(A) Make, model and serial number of purchased device.

(B) Date of purchase. 

(C) Copy of purchase order. 

(D) Location of the pneumatic pump and control device in latitude and longitude 

coordinates in decimal degrees to an accuracy and precision of five (5) decimals of a degree 

using the North American Datum of 1983.

(E) Inlet gas flow rate. 

(F) Records of continuous compliance requirements in F€ as specified in paragraphs 

(a)(1)(iv)(F)(1) through (4) of this section. 

(1) Records that the pilot flame is present at all times of operation. 

(2) Records that the device was operated with no visible emissions except for periods not 

to exceed a total of 2 minutes during any hour. 

(3) Records of the maintenance and repair log. 

(4) Records of the visible emissions test following return to operation from a 

maintenance or repair activity. 

(G) As an alternative to the requirements of paragraph (a)(1)(iv)(D) of this part, you may

maintain records of one or more digital photographs with the date the photograph was taken and 

the latitude and longitude of the pneumatic pump and control device imbedded within or stored 

with the digital file. As an alternative to imbedded latitude and longitude within the digital 

photograph, the digital photograph may consist of a photograph of the pneumatic pump and 

control device with a photograph of a separately operating GIS device within the same digital 

picture, provided the latitude and longitude output of the GIS unit can be clearly read in the 

digital photograph.
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Appendix: H-9

(b) Reporting Requirements.

(1) For each natural gas-driven pneumatic pump subject to VOC emission control

requirements, annual reports are required to include the information specified in paragraphs 

(b)(1)(i) through (iv) of this section.

(i) In the initial annual report, a certification that there is no control device on site, if 

applicable.

(ii) An identification of each natural gas-driven pneumatic pump, including the 

identification information specified in section H.2(a)(2) or (b)(3).

(iii) An identification of any sites which contain natural gas-driven pneumatic pumps and 

which installed a control device during the reporting period, where there was no control device 

previously at the site.

(iv) Records of deviations specified in paragraph (a)(1)(ii) of this section that occurred 

during the reporting period.

(v) If complying with H.2(b)(1) with a control device tested under section F(d), which 

meets the criteria in section F(d)(11) and section F(e), records specified in paragraphs 

(a)(1)(iv)(A) through (G) of this section for each pneumatic pump constructed, modified or 

reconstructed during the reporting period.

H.6 Definitions

Chemical/methanol or diaphragm pump means a gas-driven positive displacement pump 

typically used to inject precise amounts of chemicals into process streams or circulate glycol 

compounds for freeze protection.

Natural gas processing plant (gas plant) means any processing site engaged in the 

extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to 

natural gas products, or both. A Joule-Thompson valve, a dew depression valve, or a standalone 

Joule-Thompson skid is not a natural gas processing plant.
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Appendix: H-10

Natural gas-driven chemical/methanol or diaphragm pump means a chemical or 

methanol injection or circulation pump or a diaphragm pump powered by pressurized natural 

gas.
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I-1

I Fugitive Emissions Components VOC Emissions Control Requirements 

I.1 Applicability

(a) The collection of fugitive emission components at a well site with wells that produce, 

on average, greater than 15 barrel equivalents per day. The fugitive emissions requirements of 

this section do not apply to well sites that only contain wellheads.

(b) The collection of fugitive emission components at a compressor station located from 

the wellhead to the point of custody transfer to the natural gas transmission and storage segment 

or to an oil pipeline.

I.2 What VOC Emission Control Requirements Apply to the Collection of 

Fugitive Emission Components at a Well Site and a Compressor Station?

For fugitive emissions, VOC emission control requirements apply to the collection of 

fugitive emission components at a well site and compressor station (that is located from the 

wellhead to the point of custody transfer to the natural gas transmission and storage segment or 

to an oil pipeline), as specified in paragraphs (a) through (e) of this section for monitoring the 

collection of fugitive emission components. These requirements are independent of the closed 

vent system and control requirements in section D.

(a) You must monitor all fugitive emission components, as defined in section I.6, in 

accordance with paragraphs (b) through (d). You must repair all sources of fugitive emissions in 

accordance with paragraph (e). You must keep records in accordance and report in accordance 

with section I.5(a). For purposes of this section, fugitive emissions are defined as: any visible 

emission from a fugitive emission component using optical gas imaging.

(b) You must develop corporate-wide fugitive emissions monitoring plan that covers the 

collection of fugitive emission components at well sites and compressor stations in accordance 

with paragraph (c) of this section, and you must develop a site-specific fugitive emissions 

monitoring plan specific to each collection of fugitive emission components at a well site and 
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I-2

each collection of fugitive emission components at a compressor station in accordance with 

paragraph (d) of this section. Alternatively, you may develop a site-specific plan for each 

collection of fugitive emission components at a well site and each collection of fugitive emission 

components at a compressor station that covers the elements of both the corporate-wide and sitespecific plans.

(c) Your corporate-wide monitoring plan must include the elements specified in 

paragraphs (c)(1) through (c)(8) of this section, as a minimum.

(1) Frequency for conducting surveys. Monitoring surveys must be conducted at least as 

frequently as required by sections I.3 and section I.4 of this section.

(2) Technique for determining fugitive emissions.

(3) Manufacturer and model number of fugitive emission detection equipment to be used.

(4) Procedures and timeframes for identifying and fixing fugitive emission components 

from which fugitives are detected, including timeframes for fugitive emission components that 

are unsafe to repair. Your repair schedule must meet the requirements of paragraph (e) of this 

section at a minimum.

(5) Procedures and timeframes for verifying fugitive emission component repairs.

(6) Records that will be kept and the length of time records will be kept.

(7) Your plan must also include the elements specified in paragraphs (c)(7)(i) through 

(vii).

(i) Verification that your optical gas imaging equipment meets the specifications of 

paragraphs (c)(7)(i)(A) and (B) of this section. This verification is an initial verification and may

either be performed by the facility, by the manufacturer, or by a third party. For purposes of 

complying with the fugitive emissions monitoring program with optical gas imaging, a fugitive 

emission is defined as any visible emissions observed using optical gas imaging.
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I-3

(A) Your optical gas imaging equipment must be capable of imaging gases in the spectral 

range for the compound of highest concentration in the potential fugitive emissions.

(B) Your optical gas imaging equipment must be capable of imaging a gas that is half 

methane, half propane at a concentration of ≤10,000 ppm at a flow rate of ≥60 g/hr from a 

quarter inch diameter orifice.

(ii) Procedure for a daily verification check.

(iii) Procedure for determining the operator’s maximum viewing distance from the 

equipment and how the operator will ensure that this distance is maintained.

(iv) Procedure for determining maximum wind speed during which monitoring can be 

performed and how the operator will ensure monitoring occurs only at wind speeds below this 

threshold.

(v) Procedures for conducting surveys, including the items specified in paragraphs 

(c)(7)(v)(A) through (C) of this section.

(A) How the operator will ensure an adequate thermal background is present in order to 

view potential fugitive emissions.

(B) How the operator will deal with adverse monitoring conditions, such as wind.

(C) How the operator will deal with interferences (e.g., steam).

(vi) Training and experience needed prior to performing surveys.

(vii) Procedures for calibration and maintenance. Procedures must comply with those 

recommended by the manufacturer.

(d) Your site-specific monitoring plan must include the elements specified in paragraphs 

(d)(1) through (d)(3) of this section, as a minimum.

(1) Deviations from your corporate-wide plan.
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I-4

(2) Sitemap.

(3) Your plan must also include your defined walking path. The walking path must 

ensure that all fugitive emissions components are within sight of the path and must account for 

interferences.

(e) Each monitoring survey shall observe each fugitive emissions components for fugitive 

emissions. 

(f) For fugitive emissions components also subject to the repair provisions of sections 

D.2(e)(9) through (12) and (f)(4) through (7), those provisions apply instead to those closed vent 

system and covers, and the repair provisions of paragraphs (f)(1) and (2) of this section do not 

apply to those closed vent systems and covers.

(1) Each identified source is required to monitor fugitive emission components as 

specified in section I.3 and I.4. Identified fugitive emissions shall be repaired or replaced as soon 

as practicable, but no later than 15 calendar days after detection of the fugitive emissions. If the 

repair or replacement is technically infeasible or unsafe to repair during operation of the unit, the 

repair or replacement must be completed during the next scheduled shutdown or within 6 

months, whichever is earlier. 

(2) Each repaired or replaced fugitive emissions component must be resurveyed as soon 

as practical, but no later than 15 days after completion of the repair or replacement, to ensure that 

there is no leak.

(i) For repairs that cannot be made during the monitoring survey when the fugitive 

emissions are initially found, the operator may resurvey the repaired fugitive emissions 

components using Method 21 or optical gas imaging no later than 15 days of finding such 

fugitive emissions.

(ii) Operators that use Method 21 to resurvey the repaired fugitive emissions components, 

are subject to the resurvey provisions specified in paragraphs (e)(2)(ii)(A) and (B).
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I-5

(A) A fugitive emissions component is repaired when the Method 21 instrument indicates 

a concentration of less than 500 ppm above background.

(B) Operators must use the Method 21 monitoring requirements specified in section 

G.3(g).

(iii) Operators that use optical gas imaging to resurvey the repaired fugitive emissions 

components, are subject to the resurvey provisions specified in paragraphs (e)(2)(iii)(A) and (B). 

(A) A fugitive emissions component is repaired when the optical gas imaging instrument 

shows no indication of visible emissions.

(B) Operators must use the optical gas imaging monitoring requirements specified in 

paragraph (a) of this section.

I.3 Initial Compliance Demonstration

(a) Each well site with a collection of fugitive emissions components must conduct an 

initial monitoring survey within 30 days of being subject to VOC emission control requirements 

of section I.

(b) Each compressor station site with a collection of fugitive emissions components must 

conduct an initial monitoring survey within 30 days of being subject to VOC emission control 

requirements of section I.2.

I.4 Continuous Compliance Demonstration

(a) A monitoring survey of each collection of fugitive emissions components at a well 

site and a compressor station site subject to VOC emission control requirements under section I 

shall be conducted at least semiannually after the initial survey. Consecutive semiannual 

monitoring surveys shall be conducted at least four months apart.

(b) The monitoring frequency specified in paragraph (a) of this section shall be increased 

to quarterly in the event that two consecutive semiannual monitoring surveys detect fugitive 
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I-6

emissions at greater than three percent of the fugitive emissions components at a well site or at 

greater than three percent of the fugitive emission components at a compressor station subject to 

VOC emission control requirements under section I.

(c) The monitoring frequency specified in paragraph (a) of this section may be decreased 

to annual in the event that two consecutive semiannual surveys detect no fugitive emissions at

less than one percent of the fugitive emissions components at the well site, or less than one 

percent of the fugitive emissions components at a compressor station subject to VOC emission 

control requirements under section I. The monitoring frequency shall return to semiannual if a

annual survey detects fugitive emissions between one and three percent of the fugitive emissions

components at the well site, or between one and three percent of the fugitive emissions 

components at the compressor station, and shall return to quarterly if a survey detects fugitive 

emissions at greater than three percent of the fugitive emissions components at the well site, or 

greater than three percent of the fugitive emissions components at the compressor station.

I.5 Recordkeeping and Reporting Requirements

(a) Records for each monitoring survey shall be maintained as specified in paragraphs 

(a)(1) through (6) and must contain, at a minimum, the information specified in paragraphs (a)(1) 

through (a)(6). Records are required to be maintained onsite or at the nearest local field office for 

at least five years.

(1) Date of the survey.

(2) Beginning and end time of the survey.

(3) Name of operator(s) performing survey. You must note the training and experience of 

the operator.

(4) Ambient temperature, sky conditions, and maximum wind speed at the time of the 

survey.

(5) Any deviations from the monitoring plan or a statement that there were no deviations 

from the monitoring plan.
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I-7

(6) Documentation of each source of fugitive emissions (e.g. fugitive emissions 

component), including the information specified in paragraphs (a)(6)(i) through (iv) of this 

section.

(i) Location.

(ii) One or more digital photographs of each required monitoring survey being

performed. The digital photograph must include the date the photograph was taken and the 

latitude and longitude of the well site or compressor station subject to VOC emission control

requirements under section I imbedded within or stored with the digital file. As an alternative to 

imbedded latitude and longitude within the digital photograph, the digital photograph may

consist of a photograph of the monitoring survey being performed with a photograph of a 

separately operating GIS device within the same digital picture, provided the latitude and 

longitude output of the GIS unit can be clearly read in the digital photograph.

(iii) The date of the successful repair of the fugitive emission component.

(iv) The instrument used to resurvey a repaired fugitive emissions component that could 

not be repaired during the initial fugitive emissions finding.

(b) Annual reports shall be submitted for each collection of fugitive emissions 

components at a well site and each collection of fugitive emissions components at a compressor 

station subject to VOC emission control requirements under section I that include the 

information specified in paragraph (a) of this section for each monitoring survey conducted 

during the year. Multiple collection of fugitive emissions components at a well site or collection 

of fugitive emissions as a compressor station subject to VOC emission control requirements 

under section I may be included in a single annual report.

I.6 Definitions

Compressor station site means any permanent combination of one or more compressors 

that move natural gas at increased pressure into gathering or transmission pipelines, or into 

storage. 
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I-8

Fugitive emissions component means any component that has the potential to emit 

fugitive emissions of VOC at a well site or compressor station, , including but not limited to 

valves, connectors, pressure relief devices, open-ended lines, access doors, flanges, closed vent 

systems, thief hatches or other openings on a storage vessels, agitator seals, distance pieces, 

crankcase vents, blowdown vents, pump seals or diaphragms, compressors, separators, pressure 

vessels, dehydrators, heaters, instruments, and meters. Devices that vent as part of normal 

operations, such as natural gas-driven pneumatic controllers or natural gas-driven pumps, are not 

fugitive emissions components, insofar as the gas discharged from the device’s vent is not 

considered a fugitive emission. Emissions originating from other than the vent, such as the seals 

around the bellows of a diaphragm pump, would be considered fugitive emissions.

Well site means one or more areas that are directly disturbed during the drilling and 

subsequent operation of, or affected by, production facilities directly associated with any oil 

well, natural gas well, or injection well and its associated well site. For the purposes of the 

fugitive emissions standards at section I.1, well site also includes tank batteries collecting crude 

oil, condensate, intermediate hydrocarbon liquids, or produced water condensate from wells not 

located at the well site (e.g., centralized tank batteries). For the purposes of the fugitive emission 

requirements, a well site that only contains one or more wellheads is not subject to these 

requirements.
***E.O. 12866 Review – Revised Version – Do Not Quote, Cite or Release During Review***

United States

Environmental Protection

Agency

Office of Air Quality Planning and Standards

Sector Policies and Programs Division

Research Triangle Park, NC

Publication No. 

EPA-453/P-51-001

August, 2015