Oil and Natural Gas Sector: Standards for 

Crude Oil and Natural Gas Facilities 

Background Technical Support Document for the 

Proposed New Source Performance Standards 

40 CFR Part 60, subpart OOOOa 

August, 2015 
Oil and Natural Gas Sector: Standards of Performance for Crude Oil and 

Natural Gas Facilities 

By: 

EC/R, Incorporated 

501 Eastowne Dr., Suite 250 

Chapel Hill, North Carolina 27514 

Prepared for: 

Charlene Spells, Project Officer 

Office of Air Quality Planning and Standards 

Sector Policies and Programs Division 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

Office of Air Quality Planning and Standards 

Research, Triangle Park, North Carolina 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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DISCLAIMER 

This report has been reviewed by Environmental Protection Agency’s (EPA) Office of Air Quality 

Planning and Standards (OAQPS) 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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FOREWORD 

This background technical support document (TSD) provides information relevant to the proposal 

of amendments to the New Source Performance Standards (NSPS) at 40 CFR 60, subpart OOOO for 

limiting greenhouse gases (GHG), specifically methane (CH4), and volatile organic compounds (VOC) 

emissions from the Oil and Natural Gas Source Category. The proposed amendments, which are being 

proposed as 40 CFR 60, subpart OOOOa, were developed according to section 111(b)(1)(B) of the Clean 

Air Act (CAA), which requires the EPA to review and revise, as appropriate, NSPS standards. The NSPS 

review allows the EPA to identify processes in the oil and natural source category that are not regulated 

under the current NSPS but may be appropriate to regulate under NSPS based on new information. This 

would include processes that emit the current regulated pollutants, VOC and sulfur dioxide (SO2), as well 

as any additional pollutants that are identified. This document is the result of that review process. Chapter 

1 provides an introduction on NSPS regulatory authority. Chapter 2 presents an overview of the oil and 

natural gas sector and source category. Chapter 3 discusses the entire NSPS review process undertaken 

for this review. Chapters 4-8 provide information on previously unregulated emissions sources and 

revisions to standards for sources already regulated by the NSPS. Each chapter describes the emission 

source, the estimated emissions (on average) from these sources, potential control options identified to 

reduce these emissions and the cost of each control option identified. In addition, secondary impacts are 

estimated and the rationale for the proposed NSPS for each emission source is provided. Finally, Chapter 

9 summarizes other potential benefits such as natural gas savings and reductions of hazardous air 

pollutants (HAP) and global warming potential from CH4. 

 
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TABLE OF CONTENTS 

1.0 NEW SOURCE PERFORMANCE BACKGROUND ................................................................................. 1

1.1 Statutory Authority ..................................................................................................................................... 1

1.2 Regulatory History of Oil and Natural Gas Source Category ................................................................. 2

1.3 NSPS Review Process Overview ................................................................................................................ 2

2.0 OIL AND NATURAL GAS SECTOR AND SOURCE CATEGORY OVERVIEW ................................ 4

3.0 NEW SOURCE PERFORMANCE STANDARD REVIEW....................................................................... 8

3.1 Evaluation of the BSER for Existing NSPS .............................................................................................. 8

3.2 Additional Pollutants .................................................................................................................................. 8

3.3 Additional Processes .................................................................................................................................... 9

3.4 Supporting Documentation ...................................................................................................................... 10

4.0 HYDRAULICALLY FRACTURED OIL WELL COMPLETIONS AND RECOMPLETIONS ......... 11

4.1 Process Description ................................................................................................................................... 12

4.1.1 Oil Well Completions .......................................................................................................................... 12

4.1.2 Oil Well Recompletions....................................................................................................................... 13

4.2 Emission Data and Emissions Factors .................................................................................................... 13

4.2.1 Summary of Major Studies and Emission Factors.............................................................................. 13

4.2.2 Representative Completion and Recompletion Emissions................................................................... 16

4.3 Nationwide Emissions from New Sources ............................................................................................... 20

4.3.1 Determination of Number of Completions and Recompletions........................................................... 20

4.3.2 Projected Number of Completions and Recompletions for 2020 and 2025 ........................................ 23

4.3.3 Emission Estimates.............................................................................................................................. 24

4.4 Control Techniques ................................................................................................................................... 24

4.4.1 Potential Control Techniques.............................................................................................................. 24

4.4.2 Reduce Emission Completions and Recompletions............................................................................. 25

4.4.3 Completion Combustion Devices ........................................................................................................ 29

4.5 Regulatory Options ................................................................................................................................... 34

4.5.1 Evaluation of Regulatory Options....................................................................................................... 34

4.5.2 Nationwide Impacts of Regulatory Options ........................................................................................ 37

4.6 Comparison of Flowback Emissions Estimate Methodology to Measured Emissions from UT-Austin 

– Allen et al. Study .............................................................................................................................................. 43

5.0 FUGITIVE EMISSIONS STANDARDS ..................................................................................................... 45

5.1 Fugitive Emissions Description ................................................................................................................ 45

5.2 Fugitive Emissions Data and Emissions Factors .................................................................................... 46

5.2.1 Summary of Major Studies and Emission Factors.............................................................................. 46

5.2.2 Model Plants ....................................................................................................................................... 46
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5.2.2.1 Oil and Gas Production ..................................................................................................................... 49

5.3 Nationwide Emissions from New Sources ............................................................................................... 61

5.3.1 Overview of Approach........................................................................................................................ 61

5.3.2 Activity Data........................................................................................................................................ 61

5.3.3 Emission Estimates.............................................................................................................................. 65

5.4 Control Techniques ................................................................................................................................... 66

5.4.1 Potential Control Techniques............................................................................................................. 66

5.4.2 Fugitive Emissions Detection and Correction with OGI..................................................................... 67

5.4.3 Fugitive Emissions Detection and Correction with EPA Method 21 .................................................. 80

5.5 Regulatory Options ................................................................................................................................... 99

5.5.1 Evaluation of Regulatory Options for Fugitive Emissions................................................................ 100

5.5.2 Nationwide Impacts of Regulatory Options ...................................................................................... 107

6.0 PNEUMATIC CONTROLLERS ............................................................................................................... 129

6.1 Process Description ................................................................................................................................. 129

6.1.1 Pneumatic Controllers ...................................................................................................................... 129

6.2 Emissions Data and Information ........................................................................................................... 131

6.2.1 Summary of Major Studies and Emission......................................................................................... 131

6.2.2 Representative Pneumatic Device Emissions.................................................................................... 132

6.3 Nationwide Emissions from New Sources ............................................................................................. 134

6.3.1 Approach ........................................................................................................................................... 134

6.3.2 Population of Controllers Installed Annually ................................................................................... 134

6.3.3 Emission Estimates............................................................................................................................ 135

6.4 Control Techniques ................................................................................................................................. 135

6.4.1 Low-Bleed Controller Emission Reduction Potential ....................................................................... 139

6.4.2 Emission Reduction Potential ........................................................................................................... 139

6.4.3 Cost Impacts...................................................................................................................................... 140

6.4.4 Secondary Impacts ............................................................................................................................ 141

6.5 Regulatory Options ................................................................................................................................. 141

6.5.1 Evaluation of Regulatory Options..................................................................................................... 141

6.5.2 Nationwide Impacts of Regulatory Options ...................................................................................... 142

7.0 PNEUMATIC PUMPS................................................................................................................................ 143

7.1 Process Description ................................................................................................................................. 143

7.1.1 Emissions Data and Information....................................................................................................... 145

7.2 Nationwide Emissions from New Sources ............................................................................................. 147

7.2.1 Approach ........................................................................................................................................... 147
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7.2.2 Population of CIPs Installed Annually.............................................................................................. 147

7.2.3 Emission Estimates............................................................................................................................ 149

7.3 Control Techniques ................................................................................................................................. 149

7.3.1 Solar Pumps ...................................................................................................................................... 153

7.3.2 Electric Pumps .................................................................................................................................. 154

7.3.3 Instrument Air System ....................................................................................................................... 155

7.3.4 Install or Route Gas to Combustion Device ...................................................................................... 161

7.3.5 Install or Route Gas to VRU.............................................................................................................. 162

7.4 Regulatory Options ................................................................................................................................. 163

7.4.1 Evaluation of Regulatory Options..................................................................................................... 164

7.4.2 Nationwide Impacts of Selected Regulatory Options........................................................................ 176

8.0 COMPRESSORS ........................................................................................................................................ 178

8.1 Process Description ................................................................................................................................. 178

8.1.1 Reciprocating Compressors.............................................................................................................. 178

8.1.2 Centrifugal Compressors .................................................................................................................. 178

8.2 Emissions Data and Emissions Factors ................................................................................................. 179

8.2.1 Summary of Major Studies and Emissions Factors........................................................................... 179

8.2.2 Representative Reciprocating and Centrifugal Compressor Emissions............................................ 180

8.3 Nationwide Emissions from New Sources ............................................................................................. 182

8.3.1 Overview of Approach....................................................................................................................... 182

8.3.2 Activity Data for Compressors in Transmission and Storage ........................................................... 182

8.3.3 Emission Estimates............................................................................................................................ 183

8.4 Control Techniques ................................................................................................................................. 183

8.4.1 Potential Control Techniques............................................................................................................ 183

8.4.2 Reciprocating Compressor Rod Packing Replacement..................................................................... 185

8.4.3 Centrifugal Compressor Dry Seals ................................................................................................... 188

8.4.4 Centrifugal Compressor Wet Seals Routed to a Combustion Device................................................ 191

8.5 Regulatory Options ................................................................................................................................. 193

8.5.1 Evaluation of Regulatory Options..................................................................................................... 193

8.5.2 Nationwide Impacts of Selected Regulatory Options........................................................................ 194

9.0 OTHER POTENTIAL IMPACTS ............................................................................................................. 198

9.1 Natural Gas Savings ............................................................................................................................... 198

9.2 Reductions of HAP and CO2e ................................................................................................................. 200

 
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LIST OF TABLES 

Table 4-1. Major Studies Reviewed Emissions and Activity Data ............................................................................. 14 

Table 4-2. Uncontrolled Emissions Estimates from Representative Oil Well Completion or Recompletion ............. 20 

Table 4-3. Estimated Number of Total Oil Well Completions and Recompletions for a Representative Year (2012)

 ..................................................................................................................................................................................... 23 

Table 4-4. Estimated Number of Total Oil Well Completions and Recompletions for 2012, 2020 and 2025 ............ 23 

Table 4-5. Nationwide Baseline Emissions for 2012, 2020 and 2025 from Hydraulically Fractured Oil Well 

Completions and Recompletions ................................................................................................................................. 24 

Table 4-6. Reduced Emission Completion and Recompletion Emission Reductions and Cost Impacts Summary .... 33 

Table 4-7. Emission Factors from Flare Operations from AP-42 Guidelines Table 13.4-1 ........................................ 34 

Table 4-8. Nationwide Emission and Cost Analysis of Regulatory Option ................................................................ 39 

Table 4-9. Nationwide Secondary Impacts of Selected Regulatory Options for Projected Year 2020 ....................... 41 

Table 4-10. Nationwide Secondary Impacts of Selected Regulatory Options for Projected Year 2025 ..................... 42 

Table 4-11. Comparison of Flowback Emissions Estimate Methodology to Measured Emissions from the UT Austin 

- Allen et al. Study ....................................................................................................................................................... 44 

Table 5-1. Major Studies Reviewed for Emissions and Activity Data ........................................................................ 47 

Table 5-2. Estimated Average Number of Wells per Well Site in 2012 ..................................................................... 51 

Table 5-3. 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) ................................. 51 

Table 5-4. Average Fugitive Emissions Component Count for Gas Production Well Site Model Plant .................... 57 

Table 5-5. Average Fugitive Emissions Component Count for Oil Production Well Site Model Plant ..................... 57 

Table 5-6. Oil and Gas Production Operations Average Emissions Factors ............................................................... 58 

Table 5-7. Estimated Fugitive Emission Estimate for Natural Gas Production Well Site Model Plant ...................... 58 

Table 5-8. Estimated Fugitive Emission Estimate for Oil Production Well Site Model Plant .................................... 58 

Table 5-9. Average Fugitive Emissions Component Count for Gathering and Boosting Station Model Plant .......... 59 

Table 5-10. Estimated Fugitive Emission Estimate Gathering and Boosting Station Model Plant ............................ 59 

Table 5-11. Estimated Fugitive Emission Estimate for Oil and Natural Gas Transmission and Storage Model Plant 60 

Table 5-12. Nationwide Baseline Emissions for Sources Subject to NSPS Monitoring and Repair Plans in 2020 and 

2025 ............................................................................................................................................................................. 65 

Table 5-13. Nationwide Emission Reductions for OGI Monitoring and Repair Plan Options for 2020 and 2025 ..... 70 

Table 5-14. Summary of the Model Plant Cost of Control for the Annual OGI Monitoring Option - ....................... 74 

Table 5-15. Summary of the Model Plant Cost of Control for the Semiannual OGI Monitoring Option -SinglePollutant ...................................................................................................................................................................... 75 

Table 5-16. Summary of the Model Plant Cost of Control for the Quarterly OGI Monitoring Option -SinglePollutant ...................................................................................................................................................................... 76 

Table 5-17. Summary of the Model Plant Cost of Control for the Annual OGI Monitoring Option - Multi-Pollutant 

Method ........................................................................................................................................................................ 77 

Table 5-18. Summary of the Model Plant Cost of Control for the Semiannual OGI Monitoring Option - MultiPollutant Method ......................................................................................................................................................... 78 

Table 5-19. Summary of the Model Plant Cost of Control for the Quarterly OGI Monitoring Option - MultiPollutant Method ......................................................................................................................................................... 79 

Table 5-20. Percent Reduction in Emissions for EPA Method 21 Monitoring and Repair Plan Options ................... 81 

Table 5-21. Nationwide Emission Reductions for EPA Method 21 Monitoring and Repair Plan Options for 2020 and 

2025 ............................................................................................................................................................................. 81 
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Table 5-22. Summary of the Model Plant Cost of Control for the Annual Method 21 Monitoring and Repair Plan 

Options Single-Pollutant ............................................................................................................................................. 87 

Table 5-23. Summary of the Model Plant Cost of Control for the Semiannual Method 21 Monitoring and Repair 

Plan Options Single-Pollutant ..................................................................................................................................... 89 

Table 5-24. Summary of the Model Plant Cost of Control for the Quarterly Method 21 Monitoring and Repair Plan 

Options Single-Pollutant ............................................................................................................................................. 91 

Table 5-25. Summary of the Model Plant Cost of Control for the Annual Method 21 Monitoring and Repair Plan 

Options Multi-Pollutant ............................................................................................................................................... 93 

Table 5-26. Summary of the Model Plant Cost of Control for the Semiannual Method 21 Monitoring and Repair 

Plan Options Multi-Pollutant ...................................................................................................................................... 95 

Table 5-27. Summary of the Model Plant Cost of Control for the Quarterly Method 21 Monitoring and Repair Plan 

Options Multi-Pollutant ............................................................................................................................................... 97 

Table 5-28. Summary of the Cost of Control for Sub Options of Option 1 Based on OGI Monitoring ................... 103 

Table 5-29. Summary of the Cost of Control for Sub Options of Option 2 Based on Method 21 Monitoring and 

Three Repair Thresholds ........................................................................................................................................... 106 

Table 5-30. Nationwide Emission and Cost Analysis for Regulatory Option 1a – Annual OGI Monition and Repair

 ................................................................................................................................................................................... 114 

Table 5-31. Nationwide Emission and Cost Analysis for Regulatory Option 1b – Semiannual OGI Monitoring and 

Repair ........................................................................................................................................................................ 115 

Table 5-32. Nationwide Emission and Cost Analysis for Regulatory Option 2a – Annual Method 21 Monitoring and 

Repair ........................................................................................................................................................................ 116 

Table 5-33. Nationwide Emission and Cost Analysis for Regulatory Option 2b – Semiannual Method 21 Monitoring 

and Repair ................................................................................................................................................................. 119 

Table 5-34. Nationwide Emission and Cost Analysis for Regulatory Option 1a (Excluding Low-Producing Well 

Sites) .......................................................................................................................................................................... 123 

Table 5-35. Nationwide Emission and Cost Analysis for Regulatory Option 1b (Excluding Low-Producing Well 

Sites) .......................................................................................................................................................................... 124 

Table 5-36. Nationwide Emission and Cost Analysis for Regulatory Option 2a (Excluding Low-Producing Well 

Sites) .......................................................................................................................................................................... 125 

Table 5-37. Nationwide Emission and Cost Analysis for Regulatory Option 2b (Excluding Low-Producing Well 

Sites) .......................................................................................................................................................................... 127 

 

Table 6-1. Major Studies and Sources of Information Reviewed for Emissions and Activity Data ......................... 131 

Table 6-2. Average Bleed Emission Estimates per Pneumatic Controller in the Natural Gas Transmission and 

Storage Segmenta, b .................................................................................................................................................... 134 

Table 6-3. Estimated Number of Pneumatic Controllers Installed in a Typical Year in the Natural Gas Transmission 

and Storage Segment ................................................................................................................................................. 135 

Table 6-4. Nationwide Baseline Emissions from Representative Pneumatic Controller Installed in a Typical Year in 

Natural Gas Transmission and Storage Segmenta, b ................................................................................................... 135 

Table 6-5. Alternative Control Options for Pneumatic Controllers .......................................................................... 137 

Table 6-6. Estimated Annual Bleed Emission Reductions from Replacing a Representative High-Bleed Pneumatic 

Controller with a Representative Low-Bleed Pneumatic Controller in the Natural Gas Transmission and Storage 

Segment ..................................................................................................................................................................... 139 

Table 6-7. Cost Projections for Representative Pneumatic Controllers (2012)a

 ....................................................... 140 

Table 6-8. Cost-of Control for Low-Bleed Pneumatic Controllers versus High Bleed Pneumatics for the 

Transmission and Storage Segment (2012) ............................................................................................................... 141 

Table 6-9. Nationwide Cost and Emission Reduction Impacts for Selected Regulatory Option .............................. 142 
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Table 7-1. Major Studies Reviewed for Consideration of Emissions and Activity Data .......................................... 145 

Table 7-2. Average Bleed Emission Estimates Per Pneumatic Pump ....................................................................... 147 

Table 7-3. Estimated Count of Pneumatic Devices Installed in a Typical Year ....................................................... 149 

Table 7-4. Nationwide Baseline Emissions from Representative Chemical Injection Pumps Installed in a Typical 

Year for the Oil and Natural Gas Industry ................................................................................................................ 149 

Table 7-5. Alternative Control Options for Gas-Driven Pumps ................................................................................ 151 

Table 7-6. Model Plant Characterization for Replacing Gas-Driven Pumps with Instrument Air System ............... 159 

Table 7-7. Cost of Compressor Replacement for Existing Instrument Air System .................................................. 160 

Table 7-8. Secondary Impacts from Pneumatic Pumps Routed to a Combustion Device ........................................ 162 

Table 7-9. Cost of Control for Use of Instrument Air Systems at Natural Gas Processing Plants - Single-Pollutant

 ................................................................................................................................................................................... 167 

Table 7-10. Cost of Control for Use of Instrument Air Systems at Natural Gas Processing Plants - Multi-pollutant 

Method ...................................................................................................................................................................... 168 

Table 7-11. Cost of Control for Replacement with Solar-Powered or Electric Pumps at Natural Gas Processing 

Plants - Single-pollutant ............................................................................................................................................ 169 

Table 7-12. Cost of Control for Replacement with Solar-Powered or Electric Pumps at Natural Gas Processing 

Plants - Multi-pollutant Method ................................................................................................................................ 169 

Table 7-13. Cost of Control for Routing Gas-Driven Pump Emissions to a VRU - Single-pollutant Method ......... 170 

Table 7-14. Cost of Control for Routing Gas-Driven Pump Emissions to a VRU - Multi-Pollutant Method .......... 171 

Table 7-15. Estimated Cost of Control for Emission Reductions from Routing Gas-Drive Pump Emissions to a New 

Combustion Device - Single-Pollutant Method ........................................................................................................ 172 

Table 7-16. Estimated Cost of Control for Emission Reductions from Routing Gas-Drive Pump Emissions to a New 

Combustion Device - Multi-pollutant Method .......................................................................................................... 173 

Table 7-17. Cost of Control for Routing Gas-Driven Pump Emissions to an Existing Combustion Device or VRU

 ................................................................................................................................................................................... 174 

Table 7-18. Cost of Control for Routing Gas-Driven Pump Emissions to an Existing Combustion Device or VRU

 ................................................................................................................................................................................... 175 

Table 7-19. Nationwide Impacts for Gas-Driven Pumps for Selected Regulatory Option ....................................... 177 

Table 7-20. Nationwide Secondary Impacts from Pneumatic Pumps Routed to a Combustion Device ................... 177 

Table 8-1. Major Studies Reviewed for Emissions and Activity Data ...................................................................... 179 

Table 8-2. Methane Emission Factors for Reciprocating and Centrifugal Compressors .......................................... 181 

Table 8-3. Baseline Emission Estimates for Reciprocating and Centrifugal Compressors ....................................... 181 

Table 8-4. Approximate Number of New Compressors in the Transmission and Storage Segment in a Typical Yeara

 ................................................................................................................................................................................... 183 

Table 8-5. Nationwide Baseline Emissions for New Reciprocating and Centrifugal Compressors ......................... 183 

Table 8-6. Estimated Annual Reciprocating Compressor Emission Reductions from Replacing Rod Packing ....... 186 

Table 8-7. Cost of Control for Reciprocating Compressor Rod Packing Replacement ($2012) .............................. 187 

Table 8-8. Estimated Annual Centrifugal Compressor Emission Reductions from Replacing Wet Seals with Dry 

Seals .......................................................................................................................................................................... 189 

Table 8-9. Cost of Reductions for Centrifugal Compressor Using Dry Seal Compressors ($2012) ......................... 190 

Table 8-10. Estimated Annual Centrifugal Compressor Emission Reductions from Wet Seals Routed to a 

Combustion Device ................................................................................................................................................... 192 

Table 8-11. Cost of Control for Centrifugal Compressor Wet Seal Emission Routed to a Combustion Device ...... 192 

Table 8-12. Secondary Impacts from Wet Seal Emissions Routed to a Combustion Device ................................... 193 

Table 8-13. Nationwide Cost Impacts for Regulatory Option 1 ............................................................................... 196 

Table 8-14. Nationwide Cost Impacts for Regulatory Option 3 ............................................................................... 196 

Table 8-15. Nationwide Secondary Impacts from Compressor Emissions Routed to a Combustion Device ........... 197 
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Table 9-1. Estimated Nationwide Natural Gas Savings for Selected Regulatory Options ........................................ 199 

Table 9-2. HAP-to-CH4 Ratios Used to Estimate HAP Emissions ........................................................................... 200 

Table 9-3. HAP and CO2e Reductions for Selected Regulatory Options .................................................................. 201 

LIST OF FIGURES

Figure 1. Oil and Natural Gas Operations ..................................................................................................................... 7 

 
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Acronyms/Abbreviations Description 

μg/L micrograms per liter 

AEO Annual Energy Outlook 

ANGA America's Natural Gas Alliance 

API American Petroleum Institute 

bbl barrels 

BSER best system of emission reduction 

BTEX benzene, toluene, ethylbenzene and xylenes 

Btu British thermal unit 

CAA Clean Air Act 

CAGR compound annual growth rate 

CD combustion device 

CETAC-WEST Canadian Environmental Technology Advancement Corporation-WEST 

cfm cubic foot per minute 

CFR U.S. Code of Federal Regulations 

CH4 methane 

CIPs chemical injection pumps 

CO carbon monoxide 

CO2 carbon dioxide 

CO2e carbon dioxide equivalents 

COOGCC Colorado Oil and Gas Conservation Commission 

EIA Energy Information Administration 

EPA Environmental Protection Agency 

FR Federal Register 

GE General Electric 

GHG greenhouse gas 

GOR gas to oil ratio 

GRI Gas Research Institute 

H2S hydrogen sulfide 

HAP hazardous air pollutants 

Inj/With injection/withdrawal 

IR infrared 

kg/hr/comp kilograms per hour per component 

kg/hr/source kilograms per hour per source 

kW kilowatt 

lbs pounds 

LDAR leak detection and repair 

Mcf thousand cubic feet 

MMcf million cubic feet 

MMT million metric tons 

ACRONYMS AND ABBREVIATIONS
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Acronyms/Abbreviations Description 

MMtCO2e million metric tons of CO2-equivalents 

Mscf thousand standard cubic feet 

Mscf/cyl thousand standard cubic feet per cylinder 

Mscf/yr thousand standard cubic feet per cylinder per year 

NEMS National Energy Modeling System 

NESHAP National Emissions Standards for Hazardous Air Pollutants 

NGL natural gas liquids 

NOx nitrogen oxides 

NSPS New Source Performance Standards 

O&M operations & maintenance 

OAQPS Office of Air Quality and Standards 

OAR Office of Air and Radiation 

OEL open-ended line 

OGI optical gas imaging 

OVA organic vapor analyzers 

PES Preliminary Environmental Study 

PG&E Pacific Gas & Electric 

PM particulate matter 

PNAS Proceedings of the National Academy of Sciences 

ppmv parts per million by volume 

PRV pressure relief valve 

psig pounds per square inch gage 

REC renewable energy certificate 

scf standard cubic feet 

scf/hr-cylinder standard cubic feet per hour-cylinder 

scf/minute or scfm standard cubic feet per minute 

scfh standard cubic feet per hour 

SO2 sulfur dioxide 

THC total hydrocarbon 

TOC total organic compounds 

tpy tons per year 

TSD Technical Support Document 

TVA toxic vapor analyzers 

U.S. United States 

U.S.C. United States Code 

URS Corporation United Research Services Corporation 

UT Austin University of Texas, Austin 

VOC volatile organic compounds 

VRU Vapor recovery unit 

WAQD Wyoming’s Air Quality Division 
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1.0 NEW SOURCE PERFORMANCE BACKGROUND 

Standards of performance for new stationary sources are established under section 111 of the CAA 

(42 U.S.C. 7411), as amended in 1977. Section 111 directs the Administrator to establish standards of 

performance for any category of new stationary sources of air pollution which “...causes or contributes 

significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.” 

This TSD supports the proposed standards, which would control CH4, VOC and SO2 emissions from the 

oil and natural gas source category. 

1.1 Statutory Authority 

Section 111 of the CAA requires the EPA Administrator to list categories of stationary sources, if 

such sources cause or contribute significantly to air pollution which may reasonably be anticipated to 

endanger public health or welfare. The EPA must then issue performance standards for such source 

categories. A performance standard reflects the degree of emission limitation achievable through the 

application of the “best system of emission reduction” (BSER) which the EPA determines has been 

adequately demonstrated. The EPA may consider certain costs and nonair quality health and 

environmental impacts and energy requirements when establishing performance standards. Whereas CAA 

section 112 standards are issued for existing and new stationary sources, standards of performance are 

issued for new and modified stationary sources. These standards are referred to as NSPS. The EPA has the 

authority to define the source categories, determine the pollutants for which standards should be 

developed, identify the facilities within each source category to be covered and set the emission level of 

the standards. 

CAA section 111(b)(1)(B) requires the EPA to “at least every 8 years review and, if appropriate, 

revise” performance standards unless the “Administrator determines that such review is not appropriate in 

light of readily available information on the efficacy” of the standard. When conducting a review of an 

existing performance standard, the EPA has discretion to revise that standard to add emission limits for 

pollutants or emission sources not currently regulated for that source category. 

In setting or revising a performance standard, CAA section 111(a)(1) provides that performance 

standards are to “reflect the degree of emission limitation achievable through the application of the BSER 

which (taking into account the cost of achieving such reduction and any nonair quality health and 

environmental impact and energy requirements) the Administrator determines has been adequately 

demonstrated.” This level of control is referred to as the BSER. In determining the BSER, a technology 

review is conducted that identifies what emission reduction systems exist and how much the identified 
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systems reduce air pollution in practice. For each control system identified, the costs and secondary air 

benefits (or disbenefits) resulting from energy requirements and nonair quality impacts such as solid waste 

generation are also evaluated. This analysis determines the BSER. The resultant standard is usually a 

numerical emissions limit, expressed as a performance level (i.e., a rate-based standard or percent control), 

that reflects the BSER. Although such standards are based on the BSER, the EPA may not prescribe a 

particular technology that must be used to comply with a performance standard, except in instances where 

the Administrator determines it is not feasible to prescribe or enforce a standard of performance. 

Typically, sources remain free to elect whatever control measures that they choose to meet the emission 

limits. Upon promulgation, a NSPS becomes a national standard to which all new, modified or 

reconstructed sources must comply. 

1.2 Regulatory History of Oil and Natural Gas Source Category 

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). On June 24, 1985 (50 FR 26122), the EPA 

promulgated NSPS for the source category that addressed VOC emissions from leaking components at 

onshore natural gas processing plants (40 CFR part 60, subpart KKK). On October 1, 1985 (50 FR 40158), 

a second NSPS was promulgated for the source category that regulates SO2 emissions from natural gas 

processing plants (40 CFR part 60, subpart LLL). 

As a result of the review of these standards under CAA section 111(b)(1)(B), in 2012 the EPA 

published the final rule, “Standards of Performance for Crude Oil and Natural Gas Production, 

Transmission and Distribution” (40 CFR part 60, subpart OOOO). The rule expanded the existing NSPS to 

cover several oil and natural gas-related operations not previously covered, including gas well 

completions, centrifugal and reciprocating compressors, natural gas-operated 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. 

1.3 NSPS Review Process Overview 

In August 2012 (77 FR 49490) and subsequent updates (78 FR 58416, 79 FR 41752, 79 FR 79018, 

80 FR 15180 and 80 FR 15180) the EPA published the results of the NSPS review pursuant to CAA 

section 111(b)(1)(B). Today’s proposal does not address any of the covered affected facilities or pollutants 

that are already regulated in the existing NSPS, with the exception of adding methane as a regulated 

pollutant for all affected facilities currently regulated for VOC emissions. Standards are being proposed 

for currently unregulated VOC and CH4 emission sources, namely hydraulically fractured oil well 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

3

completions, fugitive emissions from well sites and compressor stations, pneumatic pumps, and pneumatic 

controllers and compressors in the transmission and storage segment. All of these amendments will be 

proposed under a new subpart, 40 CFR 60, subpart OOOOa. This proposal is a result of decisions based on 

the second and third steps of the review which involves evaluating whether there are additional pollutants 

emitted by facilities in the oil and natural gas source category that contribute significantly to air pollution 

and may reasonably be anticipated to endanger public health or welfare; and identifying and evaluating 

additional processes in the oil and natural gas source category that are not covered under the existing 

NSPS but may be appropriate to develop NSPS based on new information. The entire review process is 

described in Chapter 3.
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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2.0 OIL AND NATURAL GAS SECTOR AND SOURCE CATEGORY 

OVERVIEW 

The oil and natural gas sector includes operations involved in the extraction and production of 

crude oil and natural gas, as well as the processing, transmission and distribution of natural gas. 

Specifically for oil, the sector includes all operations from the well to the point of custody transfer at a 

petroleum refinery. For natural gas, the sector includes all operations from the well to the customer. The 

oil and natural gas operations can generally be 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. Each of these segments is briefly discussed below. 

Oil and natural gas production includes both onshore and offshore operations. Production 

operations include the wells and all related processes used in the extraction, production, recovery, lifting, 

stabilization, separation or treatment 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 includes all the portable non-self-propelled apparatus associated with those operations. Production 

sites include not only the “pads” where the wells are located, but also include stand-alone sites where oil, 

condensate, produced water and 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, gas and other materials and wastes from the wells to the 

refineries or natural gas processing plants. 

Offshore oil and natural gas production occurs on platform structures that house equipment to 

extract oil and gas from the ocean or lake floor and that process and/or transfer the oil and gas to storage, 

transport vessels or onshore. Offshore production can also include secondary platform structures 

connected to the platform structure, storage tanks associated with the platform structure and floating 

production and offloading equipment. 

There are two basic types of wells: oil wells and 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 oil refinery sector is considered separately from the oil and natural gas 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

5

sector. Therefore, at the point of custody transfer at the refinery, the oil leaves the oil and natural gas 

sector and enters the petroleum refining sector. 

Natural gas is primarily made up of CH4. However, whether natural gas is associated gas from oil 

wells or non-associated gas from 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 different 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 produced “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 natural gas liquid 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, which 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 between 40 and 100 mile intervals along the pipeline. At a compressor station, the 

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

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 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 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

6

pipelines to business and household customers. The delivery point where the natural gas leaves the 

transmission segment and enters the distribution segment is often called the “citygate.” Typically, utilities 

take ownership of the gas at the citygate. 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 gas and allow 

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

Emissions can occur from a variety of processes and points throughout the oil and natural gas 

sector. Primarily, these emissions are organic compounds such as CH4, ethane, VOC and organic HAP. 

The most common organic HAP are n-hexane and BTEX compounds (benzene, toluene, ethylbenzene and 

xylenes). Hydrogen sulfide and SO2 are emitted from production and processing operations that handle 

and treat sour gas.1

In addition, there are significant emissions associated with the reciprocating internal combustion 

engines and combustion turbines that power compressors throughout the oil and natural gas sector. 

However, emissions from internal combustion engines and combustion turbines are covered by regulations 

specific to engines and turbines and, thus, are not addressed in this action. 

In 1979, under Section 111(b)(1)(A) of the CAA, which Congress enacted as part of the 1970 

Clean Air Act Amendments, the EPA published a list of source categories for which the EPA would 

promulgate standards of performance under section 111(b) of the CAA. One of those source categories 

was “crude oil and natural gas production.” The EPA interprets the "crude oil and natural gas production" 

source category listing as generally covering the oil and natural gas industry. Specifically, with respect to 

the oil and natural gas industry, the source category is described as the production, processing, and 

transmission and storage segments of the oil and natural gas sector. The analysis supporting the NSPS as 

presented in this document addresses only emission sources in the oil and natural gas source category. 

Unless otherwise noted, use of the term "gas" refers to natural gas.

                                                            

1

 Sour gas is defined as natural gas with a maximum H2S content of 0.25 gr/100 scf (4 parts per million by volume (ppmv)) along 

with the presence of CO2.
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support 

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Figure 1. Oil and Natural Gas Sector Operations 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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3.0 NEW SOURCE PERFORMANCE STANDARD REVIEW 

Section 111(b)(1)(B) of the CAA requires the EPA to review and revise, if appropriate, NSPS 

standards. This review process consists of the following steps: 

1. Evaluation of the existing NSPS to determine whether they continue to reflect the BSER for the 

emission sources that they address; 

2. Evaluation of whether there were additional pollutants emitted that warrant regulation and for 

which there is adequate information to promulgate standards of performance; and 

3. Identification of additional processes for which it would be appropriate to develop performance 

standards, including processes that emit the currently regulated pollutants as well as any additional 

pollutants identified in step two. 

The following sections detail each of these steps. 

3.1 Evaluation of the BSER for Existing NSPS 

During development of the NSPS amendments promulgated in 2012, BSER options for 

equipment leaks at natural gas processing plants (subpart KKK) and SO2 emissions from sweetening 

units located at natural gas processing plants (subpart LLL) were evaluated, which addressed all existing 

covered sources and pollutants in the prior NSPS. Therefore, this action includes no control technology 

evaluations for those sources. In addition, this action does not further evaluate the BSER analyses for 

currently regulated affected facilities under subpart OOOO. 

3.2 Additional Pollutants 

The current NSPS (subparts KKK, LLL and OOOO) for the Oil and Natural Gas source category 

addresses emissions of VOC and SO2 from certain affected facilities. In addition to these pollutants, 

sources in this source category also emit a variety of other pollutants, most notably, air toxics. However, 

there are National Emissions Standards for Hazardous Air Pollutants (NESHAP) that address air toxics 

from the oil and natural gas source category, specifically 40 CFR subpart HH and 40 CFR subpart HHH. 

In addition, processes in the Oil and Natural Gas source category have been found to emit 

significant amounts of CH4. The Inventory of U.S. Greenhouse Gas (GHG) Emissions and Sinks: 1990-

2013 estimates 2009 CH4 emissions from Petroleum and Natural Gas Systems (not including petroleum 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

9

refineries) to be 148 MMtCO2e (million metric tons of CO2-equivalents (CO2e)).

2

 As a result, this 

proposed rule adds GHG emissions, specifically CH4, as a regulated pollutant for all currently covered 

affected facilities in the NSPS as well as the additional affected facilities identified in these amendments. 

The CH4 emissions, reductions and cost of control evaluations for affected facilities that are currently 

regulated under the rule were included in the technical support documents for the proposed and final 

NSPS and the supporting memorandum for the subsequent reconsideration for storage vessels in 2013. 

For convenience, we have summarized the information in a memorandum titled "Summary of Reductions 

of Methane Emissions and Methane Global Warming Potential For 40 CFR 60 Subpart OOOO Affected 

Facilities" available in the docket. 

Significant emissions of nitrogen oxides (NOx) also occur at oil and natural gas sites due to the 

combustion of natural gas in reciprocating engines and combustion turbines used to drive the 

compressors that move natural gas through the system, and from combustion of natural gas in heaters 

and boilers. While these engines, turbines, heaters and boilers are co-located with processes in the oil and 

natural gas sector, they are not in the Oil and Natural Gas source category and are not being addressed in 

this action. The NOx emissions from engines and turbines are covered by the Standards of Performance 

for Stationary Spark Internal Combustion Engines (40 CFR part 60, subpart JJJJ) and Standards of 

Performance for Stationary Combustion Turbines (40 CFR part 60, subpart KKKK), respectively. 

3.3 Additional Processes 

The current NSPS covers SO2 and VOC emissions from gas processing plants and VOC 

emissions from gas well completions and recompletions, pneumatic controllers, compressors and storage 

vessels. The EPA has identified several additional sources of CH4 and VOC that are included in the 

proposed standards. Specifically the EPA is proposing to regulate CH4 emissions from all affected 

facilities currently regulated under subpart OOOO that are regulated for VOC emissions. The EPA is 

also proposing to regulate CH4 and VOC from hydraulically fractured oil well completions and 

recompletions, compressors in the transmission and storage segment, gas-driven pneumatic controllers in 

the transmission and storage segment, gas-driven pneumatic pumps, and fugitive emissions from well 

sites and compressor stations. The remainder of this document presents the BSER evaluation for each of 

the new processes to be included in the NSPS. 

                                                            

2

 U.S. EPA. Inventory of U.S. GHG Emissions and Sinks: 1990-2013. Available at 

http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2015-Main-Text.pdf. 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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3.4 Supporting Documentation 

As noted above, this action follows the development of several NSPS related actions including 

the NSPS proposal in 2011 and final rule in 2012 and subsequent reconsideration of the 2012 storage 

vessel provisions in 2013. This review references several documents that were published as a 

consequence of these prior actions. For ease of presentation, the following documents are consistently 

cited in the following sections: 

 The TSD for the 2011 NSPS proposal, published in July, 2011, will be referred to in this document 

as "2011 NSPS TSD".3

 The supplemental TSD for the 2012 final NSPS standards, published April, 2012, will be referred 

to in this document as "2012 NSPS STSD".4

 The gas composition memo that was developed during the NSPS process which characterizes and 

analysis of data to determine the gas composition and develop ratios for natural gas composition to 

be used for the various segments in the development of regulations for the oil and natural gas 

sector. This document will be referred to as "2011 Gas Composition Memorandum".5

 Emissions information and counts for various emission sources were summarized from facilitylevel data submitted to the Greenhouse Gas Reporting Program (GHGRP) and data used to 

calculate national emissions in the Inventory of U.S. Greenhouse Gas Emissions and Sinks. The 

most recent published data was from 2013 and was used for various portions of the analysis. For 

the purposes of this document these data sources are referred to as "GHGRP" and “GHG 

Inventory”.6 Note that the GHGRP plans to release additional activity data in the fall of 2015 from 

its Petroleum and Natural Gas Systems source category. These data cover oil and gas operations 

reporting to the GHGRP in 2011, 2012, 2013 and 2014. These new activity data will be reviewed 

prior to finalization of this rule and incorporated into this analysis if appropriate.

 All of the calculations supporting the analyses in this document are included in the docket in the 

form of spreadsheets that are labeled corresponding to the section of the TSD. 

                                                            

3

 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. 

4

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

Gas Production, Transmission, and Distribution. Background Supplemental Technical Support Document for Proposed 

Standards. April 2012. Docket ID EPA-HQ-OAR-2010-0505-4550. 5

 Memorandum to Bruce Moore, U.S. EPA from Heather Brown, EC/R. "Composition of Natural Gas for use in the Oil and 

Natural gas Sector Rulemaking". July 2011. Docket ID EPA-HQ-OAR-2010-0505-0084. 

6

 EPA (2014) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012. U.S. Environmental Protection Agency, 

Washington D.C. EPA 430-R-15-004 Available online at: 

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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4.0 HYDRAULICALLY FRACTURED OIL WELL COMPLETIONS 

AND RECOMPLETIONS 

The 2012 NSPS promulgated requirements for control of emissions from hydraulically fractured 

natural gas well completions and recompletions. During development of the 2012 NSPS amendments, 

hydraulically fractured oil well completion and recompletion VOC emissions were estimated and 

included in the cost and impact analysis. See the 2011 NSPS TSD. At that time, it was found that the cost 

of control for oil wells was too high, and therefore, no requirements were finalized for control of VOC 

emissions from oil well completions or recompletions. The EPA was petitioned for review of the 2012 

NSPS for several issues, one of which was that petitioners believed the EPA had underestimated the 

emissions from hydraulically fractured oil well completions and recompletions, which resulted in an 

overestimation the cost of control, which was the basis for the decision to not include hydraulically 

fractured oil wells as affected facilities under subpart OOOO. 

The EPA has reevaluated hydraulically fractured oil well completion emissions based on more 

recent data and information as discussed below. As was determined with respect to gas wells, oil well 

completions and recompletions contain multi-phase processes with various sources of emissions with the 

highest emissions being from the venting of natural gas to the atmosphere during flowback. The 

flowback emissions are short-term in nature and occur as a specific event during completion of a new 

well or during recompletion activities that involve re-drilling or re-fracturing an existing well. This 

chapter describes hydraulically fractured oil well completions and recompletions, and provides estimates 

for representative oil wells and nationwide emissions. With respect to control technology, the same 

control technology can be employed to control emission from oil well completions as were found to be 

appropriate for gas well completions. As such, a BSER analysis was not necessary when considering 

control technology for application to oil well completion emission. Therefore, we evaluated costs, 

emission reductions, and secondary impacts for oil well completion and recompletions based on the 

revised emissions profile. Finally, this chapter discusses a sensitivity analysis conducted with respect to 

the natural gas production data used for the emissions analysis in comparison to field test data available 

for hydraulically fractured oil well completions. 

Because oil well completions and recompletions were included in the proposed NSPS 

amendments in 2011 (76 FR 52738), for the sake of convenience we repeat below the process description 

and control technology discussions from the 2012 NSPS TSD (Section 4.1) with minimal edits. 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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4.1 Process Description 

4.1.1 Oil Well Completions 

All oil wells must be “completed” after initial drilling in preparation for production. Oil well 

completion activities not only will vary across formations, but can vary between wells in the same 

formation. Over time, completion and recompletion activities may change due to the evolution of well 

characteristics and technology advancement. 

Well completion activities include multiple steps after the well bore hole has reached the target 

depth. These steps include inserting and cementing-in well casing, perforating the casing at one or more 

producing horizons, and often hydraulically fracturing one or more zones in the reservoir to stimulate 

production. Surface components, including wellheads, pumps, dehydrators, separators, tanks, and 

gathering lines are installed as necessary for production to begin.7

Developmental wells are drilled within known boundaries of a proven oil or gas field, and are 

located near existing well sites where well parameters are already recorded and necessary surface 

equipment is in place. When drilling occurs in areas of new or unknown potential, well parameters such 

as gas composition, flow rate, and temperature from the formation need to be ascertained before surface 

facilities required for production can be adequately sized and brought on site. In this instance, 

exploratory (also referred to as “wildcat”) wells and field boundary delineation wells typically either 

vent or combust the flowback gas. 

One completion step for improving oil production is to fracture the reservoir rock with very high 

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

fractures after fluid pressure is reduced. Natural gas emissions are a result of the backflow of the fracture 

fluids and reservoir gas at high pressure and velocity necessary to clean and lift excess proppant to the 

surface. Natural gas from the completion backflow escapes to the atmosphere during the reclamation of 

water, sand, and hydrocarbon liquids during the collection of the multi-phase mixture directed to a 

surface impoundment. As the fracture fluids are depleted, the backflow eventually contains a higher 

volume of natural gas from the formation. Due to the specific additional equipment and resources 

involved and the nature of the backflow of the fracture fluids, completions involving hydraulic fracturing 

have higher costs and vent substantially more natural gas than completions not involving hydraulic 

fracturing. 

                                                            

7

 U.S. EPA. Lessons Learned: Reduced Emissions Completions. Office of Air and Radiation (OAR): Natural Gas Star Program, 

Washington, DC, 2011. 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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4.1.2 Oil Well Recompletions 

During its lifetime, wells may need supplementary maintenance, referred to as recompletions 

(these are also referred to as workovers). Recompletions are remedial operations required to maintain 

production or minimize the decline in production. Examples of the variety of recompletion activities 

include completion of a new producing zone, re-fracture of a previously fractured zone, removal of 

paraffin buildup, replacing rod breaks or tubing tears in the wellbore, and addressing a 

malfunctioning downhole pump. During a recompletion, portable equipment is conveyed back to the 

well site temporarily and some recompletions require the use of a service rig. As with well 

completions, recompletions are highly specialized activities, requiring special equipment, and are 

usually performed by well service contractors specializing in well maintenance. Any flowback event 

during a recompletion, such as after a hydraulic fracture, will result in emissions to the atmosphere 

unless the flowback gas is captured. 

When hydraulic re-fracturing (recompletions) is performed, the emissions are essentially the 

same as new well completions involving hydraulic fracture, except that surface gas collection equipment 

will already be present at the wellhead after the initial fracture. The flowback velocity during refracturing will typically be too high for the normal wellhead equipment (separator, dehydrator, lease 

meter), while the production separator is not typically designed for separating sand. 

Flowback emissions are a result of free gas being produced by the well during well cleanup event, 

when the well also happens to be producing liquids (mostly water) and sand. The high rate flowback, 

with intermittent slugs of water and sand along with free gas, is directed to an impoundment or vessels 

until the well is fully cleaned up, where the free gas vents to the atmosphere while the water and sand 

remain in the impoundment or vessels. Therefore, nearly all of the flowback emissions originate from the 

recompletion process but are vented as the flowback enters the impoundment or vessels. Minimal 

amounts of emissions are caused by the fluid (mostly water) held in the impoundment or vessels since 

very little gas is dissolved in the fluid when it enters the impoundment or vessels. 

4.2 Emission Data and Emissions Factors 

4.2.1 Summary of Major Studies and Emission Factors 

Together with the sources of information and data reviewed during the development of the 2012 

NSPS, the EPA reviewed recent data and information as was discussed in the white paper titled “Oil and 

Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas during Ongoing 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

14

Production" published by the EPA in April, 2014.8 The more recent information and data reviewed for the 

white paper indicates that there is potential for significant emissions from oil well completions and 

recompletions. Table 4-1 presents a list of the studies or information sources consulted for development of 

the NSPS development and the 2014 white paper. The list below includes sources with information on 

hydraulically fractured gas and oil well completions and workovers. 

Table 4-1. Major Studies Reviewed Emissions and Activity Data 

Report Name Affiliation 

Year of 

Report 

Activity 

Factor(s) 

Emission 

Information

Control 

Information

GHG Mandatory Reporting Rule and 

Technical Supporting Documentsa EPA 2013 Nationwide X 

Inventory of GHG Emissions and 

Sinks: 1990-2012b, c EPA 2014 Nationwide X 

CH4 Emissions from the U.S. 

Petroleum Industry (Draft)d Radian 1996 Nationwide X 

CH4 Emissions from the U.S. 

Petroleum Industrye ICF 1999 Nationwide X 

Oil and Gas Emission Inventories for 

Western Statesf

Western Regional 

Air Partnership 2005 Regional X X 

Recommendations for Improvements 

to the Central States Regional Air 

Partnership's Oil and Gas Emission 

Inventoriesg

Central States 

Regional Air 

Partnership 

2008 Regional X X 

Oil and Gas Producing Industry in 

Your Stateh

Independent 

Petroleum 

Association of 

America 

2009 Nationwide 

Emissions from Oil and Natural Gas 

Production Facilitiesi

Texas Commission 

for Environmental 

Quality 

2007 Regional X X 

Petroleum and Natural Gas Statistical 

Dataj

U.S. Energy 

Information 

Administration 

(EIA) 

2007-2009 Nationwide 

Preferred and Alternative Methods for 

Estimating Air Emissions from Oil 

and Gas Field Production and 

Processing Operationsk

EPA 1999 X 

Supplemental Generic Environmental 

Impact Statement on the Oil, Gas and 

Solution Mining Regulatory Programl

New York State 

Department of 2009 Regional X X 

                                                            

8

 Available at http://www.epa.gov/airquality/oilandgas/2014papers/20140415completions.pdf. 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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Report Name Affiliation 

Year of 

Report 

Activity 

Factor(s) 

Emission 

Information

Control 

Information

Environmental 

Conservation 

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 Standardsm

EPA 2012 Nationwide X X 

Fort Berthold Federal Implementation 

Plann EPA 2012 Regional X X 

ERG/EC/R Contractor Analysis of 

HPDI® Datao EPA 2012 Nationwide X X 

Environmental Defense Fund Analysis 

of HPDI Datap EDF 2014 Nationwide X X 

Measurement of Methane Emissions at 

Natural Gas Production Sites in the 

United Statesq

Allen et al. 2014 Nationwide X X 

Methane Leaks from North American 

Natural Gas Systemsr Brandt et al. 2014 Nationwide X X 

a. U.S. EPA. GHG Emissions Reporting From the Petroleum and Natural Gas Industry: Background TSD. Climate 

Change Division. Washington, DC. November 2010. 84-89 pp. 

b. U.S. EPA. Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. GHG Inventory: Emission 

and Sinks 1990-2008. Washington, DC. 2010. 

c. U.S. EPA. Methodology for Estimating CH4 and CO2 Emissions from Natural Gas Systems. GHG Inventory: Emission 

and Sinks 1990-2008. Washington, DC. 2010. 

d. Radian International LLC, Methane Emissions from the U.S. Petroleum Industry, draft report for the U.S. EPA, June 

14, 1996. 

e. ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry. Prepared for the U.S. EPA. 1999. 

f. ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States. Prepared for Western 

Governors’ Association. December 27, 2005. 

g. 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. 

h. Independent Petroleum Association of America. Oil and Gas Producing Industry in Your State. 2008. 

i. Eastern Research Group, Inc. Emissions from Oil and Gas Production Facilities. Prepared for the Texas Commission 

on Environmental Quality. August 31, 2007. 

j. U.S. EIA. Annual U.S. Natural Gas Wellhead Price. EIA. Natural Gas Navigator. Retrieved December 12, 2010. 

http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm. 

k. ERG, Inc. Preferred and Alternative Methods for Estimating Air Emissions from Oil and Gas Field Production and 

Processing Operation. Prepared for the U.S. EPA. September 1999. 

l. New York State Department of Environmental Conservation. Supplemental Generic Environmental Impact Statement 

on the Oil, Gas and Solution Mining Regulatory Program (DRAFT). September 2009. 

m. See Footnote 4. 

n. Fort Berthold Indian Reservation Federal Implementation Plan (78 FR 17836). U.S. Environmental Protection Agency 

(U.S. EPA). 2012a. Technical Support Document, Federal Implementation Plan for Oil and Natural Gas Well 

Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa, and Arikara Nations), North Dakota. 

Docket Number: EPA-R08-OAR-2012-0479.U.S. EPA. 

o. Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas during Ongoing 

Production. Washington, CD. 2014. Available at 

http://www.epa.gov/airquality/oilandgas/2014papers/20140415completions.pdf.

p. Environmental Defense Fund (EDF). 2014. Co-Producing Wells as a Major Source of Methane Emissions: A Review 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

16

of Recent Analyses, March, 2014. Available at http://blogs.edf.org/energyexchange/files/2014/03/EDF-Co-producingWells-Whitepaper.pdf. Supplemental materials available at https://www.dropbox.com/s/osrom4w6ewow4ua/EDFInitial-Production-Cost-Effectiveness-Analysis.xlsx. 

q. Proceeding of the National Academy of Sciences of the United States of America (PNAS). 2013. Measurement of 

Methane Emissions at Natural Gas Production Sites in the United States. August 19, 2013. Available at 

http://www.pnas.org/content/early/2013/09/10/1304880110.abstract.

r. Brandt, A.R., et al. 2014a. Methane Leaks from North American Natural Gas Systems. Science 343, 733 (2014). 

February 14, 2014. Available at http://www.novim.org/images/pdf/ScienceMethane.02.14.14.pdf. 

4.2.2 Representative Completion and Recompletion Emissions 

As is the case for gas wells under the existing NSPS, the affected facility is considered to be the 

wellhead. Therefore, a new well drilled after the proposal date of NSPS (or in the case of oil wells, the 

proposed amendments to the NSPS) would be subject to emission control requirements. Likewise, wells 

drilled prior to the proposal date of the NSPS (or the amended NSPS) would not be subject to emission 

control requirements unless they underwent a modification after the proposal date. 

Under section 111(a) of the CAA, the term “modification” means: 

“any physical change in, or change in the method of operation of, a stationary source which 

increases the amount of any air pollutant emitted by such source or which results in the emission of any 

air pollutant not previously emitted.” 

The wellhead is defined as the piping, casing, tubing, and connected valves protruding above the 

earth’s surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a 

wellhead valve. In order to fracture an existing well during recompletion, the well would be reperforated, causing physical change to the wellbore and casing and therefore a physical change to the 

wellhead, the affected facility. Additionally, much of the emissions data on which this analysis is based 

demonstrates that hydraulic fracturing of any well results in an increase in emissions. Thus, 

recompletions using hydraulic fracturing result in an increase in emissions from the existing well 

producing operations. Based on this understanding of the work performed in order to recomplete the 

well, it was determined that a recompletion would be considered a modification under CAA section 

111(a) and thus, would constitute a new wellhead affected facility subject to NSPS. 

As previously mentioned, one specific emission source during completion and recompletion 

activities is the venting of natural gas to the atmosphere during flowback. Flowback emissions are shortterm in nature and occur as a specific event during the completion of a new well or during recompletion 

activities that involve re-drilling or re-fracturing of an existing well. For this analysis, well completion 

and recompletion emissions are estimated as the venting of emissions from the well during the initial 

phase of well preparation or during recompletion maintenance and/or re-fracturing of an existing well. 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

17

This analysis assumes wells completed/recompleted with hydraulic fracturing are found in tight 

sand, shale, or coal bed CH4 formations. The basic approach for this analysis was to use natural gas 

production data to approximate natural gas emissions from representative oil completions and 

recompletions and then estimate CH4 and VOC emissions using a the representative gas composition 

values developed in the 2011 Gas Composition Memorandum for the 2012 NSPS.9 

Based on comments received during the development of the NSPS, we recognized that there are 

instances where gas produced by a well is incidental to oil production and that the gas flow would not 

support operation of a separator with low levels of gas produced. Though, in theory, any amount of free 

gas could be separated from the liquid, the reality is that this is not practical given the design and operating 

parameters of separation units operating in the field. EIA data show that the number of "oil only" wells 

drilled from 2007-2012 was less than 20 percent.10 Therefore, we evaluated available information to 

determine a minimum threshold of gas produced. We believe that having no threshold may create a 

significant burden for operators to control emissions for these wells with just a trace of gas. 

We determined the most reasonable parameter to base the threshold was the gas to oil ratio (GOR). 

The threshold must be low enough that the oil produced is considered non-volatile. Non-volatile "black 

oils" (oil likely to not have gases or light hydrocarbons associated with it) are generally defined as having 

GOR values in the range of 200 to 900.11 Therefore, oil wells with GORs less than 300 are at the lower 

end of this range, and will not likely have enough gas associated that it can be separated. Therefore, for 

our analysis, we set a of GOR of less than 300 scf/barrel as the threshold under which an oil well 

completion would not be reasonably capable of capturing and controlling emissions. For our analysis, we 

removed these oil wells from the evaluation to determine emissions from hydraulically fractured oil wells. 

The following methodology was used to estimate the potential CH4 and VOC from hydraulically 

fractured oil well completions. 

1. The EPA obtained well production data from the DrillingInfo database dated February, 2014.12 The 

DrillingInfo database consists of oil and natural gas well information maintained by a private 

organization that provides parameters describing the location, operator, and production 

characteristics. DrillingInfo collects information on a well basis such as the operator, state, basin, 

                                                            

9

 See U.S. EPA Docket ID Number EPA-HQ-OAR-2010-0505-0084. 

10 http://www.eia.gov/todayinenergy/detail.cfm?id=13571# 11 http://petrowiki.org/Oil_fluid_characteristics 

12 DrillingInfo is a private organization specializing in compiling primarily publically available oil and gas data, conducting 

statistical analysis, and providing analysis platforms for customers. The DrillingInfo database is particularly focused on historical 

oil and gas production data and drilling permit data. 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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field, annual gas production, annual oil production, well depth, and shut-in pressure, all of which is 

aggregated from operator reports to state governments. The data extract from the DrillingInfo 

database included the population of all wells with gas or hydrocarbon liquid production during 

2010 to 2012 and with a recorded completion year of 2010 to the date of the extract (February, 

2014). 

2. The data was then processed to identify oil wells that were hydraulically fractured using a 

methodology based on a crosswalk of formation types and other information. See the ERG 

memorandum titled "2013 GHGRP Subpart W and NSPS/NESHAP DrillingInfo Processing 

Methodology" available in the docket for a detailed description of the process to identify 

hydraulically fractured oil wells from the total oil well population. 

3. From the dataset of hydraulically fractured oil wells, the EPA identified the wells completed in 

2012 using the "completion year" record or the year of the "first month of production". Wells with 

a completion year of 2012 could have been completed for the first time in 2012 or could have been 

re-completed (i.e., re-fractured in 2012). The EPA also removed all wells not characterized in the 

DrillingInfo database as defined as “oil,” “gas” or “oil and gas” from the dataset. 

4. For the above identified hydraulically fractured oil well population, the EPA calculated the gas to 

oil ratio (GOR) by dividing the standard cubic feet (scf) of gas produced during the first month of 

production by the barrels (bbl) of petroleum liquid produced during the first month. The EPA then 

used the GOR to categorize the wells into oil and gas wells. Oil wells were defined to be those 

wells with a GOR of less than 100,000 scf/bbl. This threshold was chosen because it is consistent 

with the threshold used in the EPA National Emissions Inventory Oil and Gas Emission Estimation 

Tool and the threshold used in several states, including Texas13 and New Mexico14. 

5. Based on the calculated GOR for the wells identified above, we eliminated from the evaluation 

wells with a GOR of less than 300 scf of gas per barrel produced. 

6. The EPA then calculated the following average daily gas production values for each oil well; 

 Average daily gas production over the first month of operation by dividing the total gas 

production in the first month of operation by the average number of days in a month 

(30.42); 

 Average daily gas production over the first 6 months of operation by dividing the total gas 

                                                            

13 Available at 

http://info.sos.state.tx.us/pls/pub/readtac$ext.TacPage?sl=R&app=9&p_dir=&p_rloc=&p_tloc=&p_ploc=&pg=1&p_tac=&ti=1

6&pt=1&ch=3&rl=79. 14 Available at http://164.64.110.239/nmac/parts/title19/19.015.0002.htm. 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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production in the first six months of operation by the average number of days in 6 months 

(182.5); and 

 Average daily gas production over the first year of operation by dividing the total gas 

production in the first year of operation by the total days in one year (365). 

7. The EPA assumed that the average daily gas production during the first month was representative 

of the daily potential emissions during a hydraulically fractured oil well completion. Therefore, the 

estimated gas production from a representative oil well completion was determined by taking the 

average of the average daily natural gas production during the first month of operation for each of 

the above identified oil well (i.e., hydraulically fractured, and completed in 2012). 

8. To determine the potential CH4 and VOC emissions for a representative oil well completion or 

recompletion, we converted the average natural gas potential emissions per day to short tons of 

potential CH4 and VOC emissions. The conversion factors used are those developed for the NSPS 

and outlined in the memorandum titled "Composition of Natural Gas for use in the Oil and Natural 

Gas Sector Rulemaking", available in the docket.15 Specifically, we assume natural gas is 46.71% 

CH4 by volume, the density of CH4 is 0.0208 tons per Mcf, and that there is 0.8374 lbs of VOC per 

pound of CH4. 

We then calculated the potential VOC and CH4 emissions during a hydraulically fractured oil 

well flowback by multiplying potential CH4 and VOC emissions per day by the number of days in the 

average flowback event. The data sources referenced in the white papers noted a range of flowback 

duration from 1-10 days. Some of the values in the ranges were based on study observation (e.g. Allen et 

al.) and some based on assumptions. Comments on the oil well completion white paper supported a 

flowback duration on the low end of the range. Our analysis assumes an oil well flowback duration is the 

lowest end of the gas well flowback duration towards the low end of that range, 3 days. 

Table 4-2 presents the estimated potential (i.e., uncontrolled) emissions from a representative oil 

well completion or recompletion. The data sources in the white papers and comments received on the 

white papers showed a broad range of potential emissions estimates (8 to around 200 tons CH4 per 

completion or workover) for hydraulically fractured oil well completions. Some of the values were 

developed using data on gas production and assumptions about flowback; others used measurement data. 

The estimate presented in the table below was developed using a method relying on flowback and gas 

production data, which allowed the EPA to develop a factor that reflects GOR thresholds that exclude gas 

wells and oil wells that produce very little gas. The estimates in the table below represent emissions from 

                                                            

15 See footnote 5. 
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20

that population of wells, in the absence of controls. To calculate emissions to the atmosphere using these 

values, additional information on gas that is not emitted (e.g. through use of RECs or flaring) is needed to 

reduce the potential value. 

Table 4-2. Uncontrolled Emissions Estimates from Representative Oil Well Completion or 

Recompletion 

Average Daily Production 

Natural Gas 

(Mcf/event) 

Potential Emissions 

CH4

 a 

(tons/event) 

Potential Emissions 

VOC b 

(tons/event) 

3-Day Completion or 

Recompletion Event 999 9.72 8.14 

a. It is assumed CH4 comprises 46.732 percent by volume of natural gas. The factor used to convert CH4 from volume to 

weight is 0.0208 tons CH4 per thousand cubic feet (Mcf) of CH4.

16 

b. Assumes 0.8374 lb. VOC/lb. CH4. 

4.3 Nationwide Emissions from New Sources 

4.3.1 Determination of Number of Completions and Recompletions 

The first step in this analysis is to estimate nationwide baseline emissions. In order to develop the 

baseline emissions, we estimate the average number of new wells that would be affected using the 

number of completions and recompletions performed in a typical year as derived from the DrillingInfo 

database extract as described above. The EPA used 2012 as the base year for this analysis. This value 

was then multiplied by the potential uncontrolled emissions per well completion listed in Table 4-2. 

The DrillingInfo database includes the most recent completion date for all reported wells in the US. 

Therefore, the methodology described above for calculating the number of hydraulically fractured oil well 

completions from the HPDI® database in 2012 identifies wells initially fractured in 2012 and wells that 

were refractured (recompletions) in 2012. Because these recompletions are included in the database and 

resulting extracted dataset, it is not necessary to calculate a refracture frequency. 

To more accurately estimate baseline emissions for this analysis, and to ensure no emission 

reduction benefits were calculated for sources already being controlled, it was necessary to evaluate the 

number of completions and recompletions already subject to regulation. The number of completions and 

recompletions already being controlled in the absence of federal regulation was estimated based on the 

existing State regulations that require control measures for completions and recompletions. Although 

there may be regulations issued by other local ordinances for cities and counties throughout the U.S., the 

                                                            

16 U.S EPA. Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: 

Emission and Sinks 1990-2008. Washington, DC. 2010. Appendix B, Pgs. 87-89. 
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number of wells impacted by local (as opposed to state level) regulations could not be determined 

because data for wells subject to county or local ordinance level regulations are not available. Therefore, 

the calculated percentage of wells subject to state regulation based on the identified State regulations 

should be considered a conservative estimate. 

In order to determine the number of completions and recompletions that are already controlled 

under State regulations, the DrillingInfo database extract well count data (described above) was 

analyzed to determine the percentage of new wells currently undergoing completion and recompletion in 

the States identified as having existing controls. Colorado and Wyoming were the only States identified 

as requiring controls on completions prior to NSPS review. The State of Wyoming’s Air Quality 

Division (WAQD) requires operators to complete wells without flaring or venting where the following 

criteria are met: (1) the flowback gas meets sales line specifications and (2) the pressure of the reservoir 

is high enough to enable REC. If the above criteria are not met, then the produced gas is to be flared.17 

The WAQD requires that, “emissions of VOC and HAP associated with the flaring and venting of 

hydrocarbon fluids (liquids and gas) associated with well completion and recompletion activities shall 

be eliminated to the extent practicable by routing the recovered liquids into storage tanks and routing the 

recovered gas into a gas sales line or collection system.” Similar to Wyoming, the Colorado Oil and Gas 

Conservation Commission (COOGCC) requires a renewable energy certificate (REC) for both oil and 

natural gas wells.18 It was assumed for this analysis that the ratio of wells in Colorado and Wyoming to 

the total number of wells in the U.S. represents the percentage of controlled wells for well completions. 

The ratio of wells in Wyoming to the number of total nationwide wells was assumed to represent the 

percentage of controlled well recompletions as it was the only State identified as having regulations 

directly regulated to recompletions. We used the referenced GOR of less than (<) 100,000 scf/bbl for oil 

wells to identify the oil wells located in Wyoming and Colorado. From this review it was estimated that 

7 percent of completions are controlled in absence of federal regulation. For the base year 2012 we 

estimated a total number of completions and recompletions to be 20,422. From this number we removed 

all oil wells below the GOR threshold of 300 scf per barrel, as discussed above resulting in a total 

number completions and recompletions of 15,594. 

Finally, we determined the number of exploratory oil well completions based on the percentage 

breakdown between exploratory and development wells in the National Energy Modeling System 

                                                            

17 Wyoming BACT permitting guidance. Available at 

http://deq.state.wy.us/aqd/Oil%20and%20Gas/September%202013%20FINAL_Oil%20and%20Gas%20Revision_UGRB.pdf. 18 COGCC 805 Series Rules (805.b.(3)A). Available at http://cogcc.state.co.us/ and the Colorado Code of Regulations at: 

http://www.sos.state.co.us/CCR/Welcome.do.   
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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(NEMS). 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. The NEMS source code is publicly 

available and fully documented. The source code and accompanying documentation is released annually 

when a new AEO is produced. Because of the availability of NEMS, numerous agencies, national 

laboratories, research institutes, and academic and private-sector researchers have used NEMS to analyze 

a variety of issues. NEMS models the dynamics of energy markets and their interactions with the broader 

U.S. economy. Based on the NEMS AEO 2014 Reference Case, 3.8 percent of oil wells are exploratory 

and 96.2 percent are development wells. 

In addition, as for the development of the 2012 NSPS for gas well completions, the EPA is aware 

that some oil well completions and workovers are controlled voluntarily using RECs or combustion 

devices. However, we could not identify a national level data source on this practice from which we 

could estimate the numbers of voluntarily controlled oil well completions. Therefore, due to lack of data 

and a reliable benchmark for estimating the number of voluntarily controlled completions, we assumed 

zero for our analysis of baseline emissions. 

Table 4-3 summarizes the estimated number of hydraulically fractured oil well completions 

derived from our analysis detailed above. 

 
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Table 4-3. Estimated Number of Hydraulically Fractured Oil Well Completions and Recompletions 

for a Representative Year (2012) 

Well Completion Category 

Estimated Number of 

Total Completions and 

Recompletions 

Estimated Number of 

Controlled Completions 

and Recompletionsa

Estimated Number of 

Uncontrolled Completions 

and Recompletions 

1. Developmental Oil Well 15,002 1,190 13,812 

2. Exploratory/Delineation Oil 

Well 592 47 545 

 a. Reflects completions and recompletions covered by state regulations in Colorado and Wyoming.

4.3.2 Projected Number of Completions and Recompletions for 2020 and 2025 

For our analysis, we project the activity factors for future dates. In order to determine nationwide 

impacts of the number of new oil well completions and recompletions, we used the base year of 2012 

activity data as described above and projected activity numbers for the years 2020 and 2025 based on 

predictions from the NEMS Oil and Gas Supply Model. We calculated the compound annual growth rate 

(CAGR) between 2012 and 2015 for development and exploratory oil wells based on the AEO 2014 

Reference Case. The CAGR for development wells was found to be -.01 percent and the CAGR for 

exploratory wells was found to be 6.03 percent. These factors were used to calculate the number of 

exploratory and development oil well completion for the years 2020 and 2015. 

The number of projected estimated well completions and recompletions for each well source 

subcategory used in our analysis is summarized in Table 4-4. 

Table 4-4. Estimated Number of Oil Well Completions and Recompletions for 2020 and 2025 

Well Source Subcategory

Estimated Number of 

Total Completions and 

Recompletions

Estimated Number of 

Controlled Completions 

and Recompletionsa

Estimated Number of 

Uncontrolled Completions 

and Recompletions

Base Year 2012 

1. Developmental Oil Well 15,002 1,190 13,812 

2. Exploratory Oil Well 592 47 545 

Projected Year 2020

1. Developmental Oil Well 15,707 1,901 13,806 

2. Exploratory Oil Well 946 75 870 

Projected Year 2025 

1. Developmental Oil Well 16,200 2,396 13,803 

2. Exploratory Oil Well 1,267 101 1,166 

a. Reflects completions and recompletions covered by state regulations in Colorado and Wyoming.
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4.3.3 Emission Estimates 

Using the estimated emissions per source as shown in Table 4-2, number of uncontrolled and 

controlled wells at baseline, described above, nationwide emission estimates for oil well completions 

and recompletions in the base year 2012 and projected completions and recompletions for the projected 

years 2020 and 2025 were calculated and are summarized in Table 4-5. All values have been rounded 

to the nearest ton for estimation purposes. 

Table 4-5. Nationwide Baseline Emissions for 2020 and 2025 from Hydraulically Fractured Oil Well 

Completions and Recompletions 

Well Source Subcategory 

Emissions Per Event 

(tpy) 

Number of 

Uncontrolled 

Wellsa

Baseline Nationwide 

Emissions

 (tpy) 

CH4 VOC CH4

b VOCb

Base Year 2012 

All Oil Wells 9.72 8.14 14,357 139,542 116,853 

1. Developmental Oil Wells 9.72 8.14 13,812 134,245 112,417 

2. Exploratory/Delineation 

Oil Wells 9.72 8.14 545 5,297 4,436 

Projected Year 2020 

All Oil Wells 9.72 8.14 14,677 142,649 119,454 

1. Developmental Oil Wells 9.72 8.14 13,806 134,188 112,369 

2. Exploratory/Delineation 

Oil Wells 9.72 8.14 870 8,460 7,085 

Projected Year 2025 

All Oil Wells 9.72 8.14 14,970 145,496 121,839 

1. Developmental Oil Wells 9.72 8.14 13,803 134,160 112,345 

2. Exploratory/Delineation 

Oil Wells 9.72 8.14 1,166 11,337 9,493 

a. The number of controlled and uncontrolled wells estimated based on State regulations. 

b. Based on the assumption that VOC content is 0.8374 lbs VOC per pound CH4. This estimate accounts for 5 percent of 

emissions assumed as vented even when controlled. These values do not account for secondary emissions from portion of gas 

that is directed to a combustion device. 

4.4 Control Techniques 

4.4.1 Potential Control Techniques 

The EPA considered the same two techniques that have been proven to reduce emissions from well 

completions and recompletions that were evaluated for development of the NSPS and codified for gas well 

completions and recompletions; specifically RECs and completion combustion. As with natural gas wells, 

the use of a REC not only reduces emissions but delivers natural gas product to the sales meter that would 

typically be vented. Completion combustion destroys the organic compounds. As both of these techniques 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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were determined to be BSER for gas wells for the NSPS (the use of REC was determined to be BSER 

when the recovered gas can be directed to a sales line, and completion combustion was determined to 

BSER when it is not feasible to direct the gas to a sales line), and based on our research as published in the 

oil completions white paper, these technologies have been found to be technically feasible for oil well 

completions and recompletions, and are in use in the industry to control emissions from oil wells. We 

identified no other potential control options for oil well completions. For the sake of convenience, the 

description sections included below are from the 2012 NSPS TSD with limited edits. The following 

sections describe the cost impact of these technologies with respect to oil well completions based on our 

current analysis of emissions. 

4.4.2 Reduce Emission Completions and Recompletions 

4.4.2.1 Description 

 Reduced emission completions, also referred to as “green” completions, use specially designed 

equipment at the well site to capture and treat gas so it can be directed to the sales line. This process 

prevents some natural gas from venting and results in additional economic benefit from the sale of 

captured gas and, if present, gas condensate. Additional equipment required to conduct a REC may 

include additional tankage, special gas-liquid-sand separator traps, and a gas dehydrator.19 

In many cases, portable equipment used for RECs operate in tandem with the permanent 

equipment that will remain after well drilling is completed. In other instances, permanent equipment is 

designed (e.g. oversized) to specifically accommodate initial flowback. Some limitations exist for 

performing RECs since technical barriers fluctuate from well to well. Three main limitations include the 

following for RECs: 

 Proximity of pipelines. For exploratory wells, no nearby sales line may exist. The lack of a nearby 

sales line incurs higher capital outlay risk for exploration and production companies and/or 

pipeline companies constructing lines in exploratory fields. The State of Wyoming has set a 

precedent by stating proximity to gathering lines for wells is not a sufficient excuse to avoid RECs 

unless they are deemed exploratory, or the first well drilled in an area that has never had oil and 

gas well production prior to that drilling instance (i.e., a wildcat well).20 In instances where 

formations are stacked vertically and horizontal drilling could take place, it may be possible that 

                                                            

19 U.S. EPA Fact Sheet No. 703: Green Completions. OAR: Natural Gas Star Program. Washington, DC. September 2004. 20 Memorandum to Bruce Moore, U.S. EPA from Denise Grubert, EC/R. API Meeting Minutes. July 2010. 
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existing surface REC equipment may be located near an exploratory well, which would allow for a 

REC. 

 Pressure of produced gas. During each stage of the completion/recompletion process, the 

pressure of flowback fluids may not be sufficient to overcome the sales line backpressure. This 

pressure is dependent on the specific sales line pressure and can be highly variable. In this case, 

combustion of flowback gas is one option, either for the duration of the flowback or until a point 

during flowback when the pressure increases to flow to the sales line. Another control option is 

compressor applications. One application is gas lift which is accomplished by withdrawing gas 

from the sales line, boosting its pressure, and routing it down the well casing to push the fracture 

fluids up the tubing. The increased pressure facilitates flow into the separator and then the sales 

line where the lift gas becomes part of the normal flowback that can be recovered during a REC. 

Another potential compressor application is to boost pressure of the flowback gas after it exits 

the separator. This technique is experimental because of the difficulty operating a compressor on 

widely fluctuating flowback rate. 

 Inert gas concentration. If the concentration of inert gas, such as nitrogen or CO2, in the 

flowback gas exceeds sales line concentration limits, venting or combustion of the flowback may 

be necessary for the duration of flowback or until the gas energy content increases to allow flow 

to the sales line. Further, since the energy content of the flowback gas may not be high enough to 

sustain a flame due to the presence of the inert gases, combustion of the flowback stream would 

require a continuous ignition source with its own separate fuel supply. 

4.4.2.2 Emission Reduction Potential 

RECs are an effective emissions reduction method for oil well completions and recompletions 

performed with hydraulic fracturing based on the estimated flowback emissions described in Section 4.2. 

The emissions reductions vary according to reservoir characteristics and other parameters including 

length of completion, number of fractured zones, pressure, gas composition, and fracturing 

technology/technique. Based on information presented in the white papers, this analysis assumes 90 

percent of flowback gas can be recovered during a REC.21 Any amount of gas that cannot be recovered 

can be directed to a completion combustion device in order to achieve a minimum 95 percent reduction 

in emissions. 

                                                            

21 Memorandum to Bruce Moore, U.S. EPA from ICF Consulting. Percent of Emissions Recovered by Reduced Emission 

Completions. May 2011. 
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4.4.2.3 Cost Impacts 

All completions incur some costs to a company. Performing a REC will add to these costs. 

Equipment costs associated with RECs vary from well to well. High production rates may require larger 

equipment to perform the REC and will increase costs. If permanent equipment, such as a glycol 

dehydrator, is already installed or is planned to be in place at the well site as normal operations, costs 

may be reduced as this equipment can be used or resized rather than installing a portable dehydrator for 

temporary use during the completion. Some operators normally install equipment used in RECs, such as 

sand traps and three-phase separators, further reducing incremental REC costs. The EPA received 

information and comment from multiple technical experts that the equipment necessary to perform a 

REC for an oil well completion is the same as that for a gas well completion. 

Therefore, as was determined in the 2011 NSPS TSD22, the annual cost of performing a REC 

was estimated to be $12,735 for a representative well completion lasting 3 days23. For our analysis, the 

cost is adjusted to 2012 dollars using the Gross Domestic Product: Implicit Price Deflator.24 The 

resulting cost for performing a REC for a well completion or recompletion lasting 3 days is estimated to 

be $13,459. 

Monetary savings associated with additional gas captured to the sales line is estimated based on a 

natural gas price of $4.00 per Mcf.25 It was assumed that all gas captured would be included as sales gas. 

Therefore, assuming that 90 percent of the gas is captured and sold, this equates to a total recovery of 899 

Mcf of natural gas per completion or recompletion. The estimated value of the recovered natural gas for a 

representative natural gas well with hydraulic fracturing is approximately $3,597. When considering 

these savings from REC, for a completion or recompletion with hydraulic fracturing, there is a net cost 

on the order of $9,862 per completion. 

RECs are considered one-time events per well; therefore annual costs were conservatively assumed 

to be the same as capital costs. The cost per ton of emissions reduced was then calculated in two ways. 

The first method, the single-pollutant method, allocates all of the costs to each pollutant separately. The 

                                                            

22 See footnote 3. 

23 This cost was based on state of the industry in 2006 and adjusted to 2008 US Dollars. For the 2012 NSPS we determined a 

cost per day value, however, the 2012 NSPS applied this per day cost to a 7-day event duration. Here we use the same cost per 

day and a 3-day event duration. 

24 Available at http://research.stlouisfed.org/fred2/series/GDPDEF/. 25 When including the additional natural gas recovery in the cost analysis, we assume that producers are paid $4 per thousand 

cubic feet (Mcf) for the recovered gas at the wellhead. The Energy Information Administration’s 2014 Annual Energy 

Outlook forecasted wellhead prices paid to lower 48 state producers to be $4.46/Mcf in 2020 and $5.06/Mcf in 2025. The 

$4/Mcf price assumed in this RIA is intended to reflect the AEO estimate but simultaneously be conservatively low. 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

28

second method, the multi-pollutant method, allocates costs among the pollutants that a given technology 

reduced (i.e., methane and VOC). This proration was based on estimates of the percentage reduction 

expected for each pollutant. 

Based on expected emission reductions from the use of a REC, the cost of control for methane is 

$1,539 per ton and $1,837 per ton of VOC when 100 percent of the cost is attributed to each pollutant and 

$769 per ton of methane and $919 per ton of VOC when the total cost is allocated equally between 

methane and VOC (i.e., 50 percent to methane and 50 percent to VOC). Table 4-6 provides a summary of 

REC cost per ton of emission reduction. 

Because a REC accomplishes gas savings, the cost of control for methane is $1,127 per ton and 

$1,346 per ton of VOC when 100 percent of the cost is attributed to each pollutant and the monetary gas 

savings is considered. Likewise, the cost is $564 per ton of methane and $673 per ton of VOC when the 

total cost is reduced by the gas savings and is allocated equally between methane and VOC (i.e., 50 

percent to methane and 50 percent to VOC). Table 4-6 provides a summary of REC cost per ton of 

emission reduction. 

In order to accomplish 95 percent control, the combination of a combustion device and the REC 

can be used. For the combined REC and combustion device scenario, the cost of control for methane is 

$1,861 per ton and $2,222 per ton of VOC when 100 percent of the cost is attributed to each pollutant 

individually. The cost is $930 per ton of methane and $1,111 per ton of VOC when the total cost is 

allocated equally between methane and VOC (i.e., 50 percent to methane and 50 percent to VOC). 

When gas savings is considered, for the combined REC and combustion device, the cost of control 

for methane is $1,471 per ton and $1,757 per ton of VOC when 100 percent of the cost is attributed to 

each pollutant individually and the monetary gas savings is considered. Likewise, the cost is $736 per ton 

of methane and $879 per ton of VOC when the total cost is reduced by the gas savings and is allocated 

equally between methane and VOC (i.e., 50 percent to methane and 50 percent to VOC). Table 4-6 

provides a summary of REC cost per ton of emission reduction. 

4.4.2.4 Secondary Impacts 

A REC is a pollution prevention technique that is used to recover natural gas that would 

otherwise be emitted. No secondary emissions (e.g., NOx, PM, etc.) would be generated, no wastes 

should be created, no wastewater generated, and no electricity needed. Therefore, there are no secondary 

impacts expected due to REC. 
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4.4.3 Completion Combustion Devices 

4.4.3.1 Description 

Completion combustion is a high-temperature oxidation process used to burn combustible 

components, mostly hydrocarbons, found in waste streams.26 Completion combustion devices are used 

to control VOC in many industrial settings, since the completion combustion device can normally handle 

fluctuations in concentration, flow rate, heating value, and inert species content.27 Completion 

combustion devices commonly found on drilling sites are rather crude and portable, often installed 

horizontally due to the liquids that accompany the flowback gas. These devices can be as simple as a 

pipe with a basic ignition mechanism and discharge over a pit near the wellhead. However, the flow 

directed to a completion combustion device may or may not be combustible depending on the inert gas 

composition of flowback gas, which would require a continuous ignition source. Sometimes referred to 

as pit flares, these types of combustion devices do not employ an actual control device, and are not 

capable of being tested or monitored for efficiency. They do provide a means of minimizing vented gas 

and is preferable to venting. For the purpose of this analysis, the term completion combustion device 

represents all types of combustion devices including pit flares. 

4.4.3.2 Emission Reduction Potential 

As mentioned previously, it is difficult to accurately measure the destruction efficiency of a 

completion combustion device. The actual destruction efficiency achieved in practice can be expected to 

vary with the amount of noncombustible gas and liquids in the gas flow. For the purposes of this 

analysis, a destruction efficiency of 95 percent, consistent with the expected destruction efficiency of a 

properly designed and operated flare, was assumed for completion combustion devices over the duration 

of the completion or recompletion. If the energy content of natural gas is low, then the combustion 

mechanism can be extinguished by the flowback gas. Therefore, it is more reliable to install an igniter 

fueled by a consistent and continuous ignition source. This scenario would be especially true for 

energized fractures where the initial flowback concentration will be extremely high in inert gases. This 

analysis assumes the use of a continuous ignition source with an independent external fuel supply to 

achieve an average of 95 percent control over the entire flowback period. Additionally, because of the 

nature of the flowback (i.e., with periods of water, condensate, and gas in slug flow), conveying the 

entire portion of this stream to a completion combustion device or other control device is not always 

feasible. Because of the exposed flame, open pit flaring can present a fire hazard or other undesirable 

                                                            

26 U.S. EPA. AP-42, Fifth Edition, Volume I, Chapter 13.5 Industrial Flares. OAQPS. 1991. 

27 U.S. EPA. Air Pollution Control Technology Fact Sheet: FLARES. Clean Air Technology Center.
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impacts in some situations (e.g., dry, windy conditions, proximity to residences, etc.). As a result, we are 

aware that owners and operators may not be able to combust unrecoverable gas safely in every case. 

The General Provisions to 40 CFR part 60 specify design and operational requirements for flares to 

assure that a high level of destruction efficiency is achieved at all times (see 40 CFR 60.18(b)). Because 

completion combustion devices are not flares, the requirements of 40 CFR 60.18(b) do not apply to them. 

Concerns have been raised on applicability of 40 CFR 60.18 within the oil and gas industry including for 

the production segment.28,29,30 The design and nature of completion combustion devices must handle 

multiphase flow and stream compositions that vary during the flowback period. Thus, the applicability 

criterion that specifies conditions for flares used in highly industrial settings may not be appropriate for 

flares typically used to control emissions from well completions and recompletions. 

4.4.3.3 Cost Potential 

An analysis estimating the cost for wells including completion combustion devices was 

conducted for the 2012 NSPS, resulting in an estimated average completion combustion device cost 

of approximately $3,523 (2008 dollars).31 For our analysis, this cost was adjusted to 2012 dollars using 

the Gross Domestic Product: Implicit Price Deflator 32 resulting in an estimated annual cost of $3,723 

per well completion. As with the REC, because completion combustion devices are purchased for these 

one-time events, annual costs were conservatively assumed to be equal to the capital costs. 

It is assumed that the cost of a continuous ignition source is included in the combustion 

completion device cost estimations. It is understood that multiple completions and recompletions can be 

controlled with the same completion combustion device, not only for the lifetime of the combustion 

device but within the same yearly time period. However, to be conservative, costs were estimated as the 

total cost of the completion combustion device itself, which corresponds to the assumption that only one 

device will control one completion per year. The cost per ton of emissions reduced was then calculated 

in two ways. The first method allocated all of the costs to each pollutant individually. The second 

method allocated costs among the pollutants that a given technology reduced (i.e., CH4 and VOC). This 

allocation was based on estimates of the percentage reduction expected for each pollutant. Completion 

                                                            

28 See footnote 20. 

29 Memorandum to Bruce Moore from Denise Grubert. API Meeting Minutes. EC/R, Incorporated. October 2010. 

30 Memorandum to Bruce Moore from Denise Grubert. API Meeting Minutes Attachment 1: Review of Federal Air Regulations 

for the Oil and Natural Gas Sector 40 CFR Part 60, Subparts KKK and LLL; 40 CFR Part 63 Subparts HH and HHH. EC/R, 

Incorporated. February 2011.

31 The Chemical Engineering Cost Index was used to convert dollar years. For the combustion device the 2009 value equals the 

2009 average value for the combustion device is $3,195. 

32 See footnote 24. 
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combustion devices have a cost of control of $403 per ton of methane and $481 per ton of VOC for oil 

well completions and recompletions when 100 percent of the cost is attributed to methane and 100 

percent to VOC. Where the cost is prorated to both pollutants equally (i.e., a 50 percent to methane and 

50 percent to VOC), the cost of control is $202 per ton of methane and $241 per ton of VOC. The cost 

impacts of using a completion combustion device to reduce emissions from representative 

completions/recompletions are provided in Table 4-6. 

Since this analysis assumed completion combustion devices achieve 95 percent efficiency over 

the duration of flowback, it is likely the secondary emission estimations are lower than in actuality (i.e. 

AP-42 assumes 98 percent efficiency). In addition due, to the potential for the incomplete combustion of 

natural gas across the completion combustion device plume, the likelihood of additional NOx formulating 

is also likely. The degree of combustion is variable and depends on the rate and extent of fuel mixing 

with air and on the flame temperature. Moreover, the actual NOx (and carbon monoxide (CO)) emissions 

may be greatly affected when the raw gas contains hydrocarbon liquids and water. For these reasons, the 

nationwide impacts of combustion devices discussed in Section 4.5 should be considered minimum 

estimates of secondary emissions from combustion devices. 

4.4.3.4 Secondary Impacts 

Noise and heat are the two primary undesirable outcomes of completion combustion device 

operation. In addition, combustion and partial combustion of many pollutants also create secondary 

pollutants including NOx, CO, sulfur oxides (SOx), CO2, and smoke/particulates. The degree of 

combustion depends on the rate and extent of fuel mixing with air and the temperature maintained by the 

flame. Most hydrocarbons with carbon-to-hydrogen ratios greater than 0.33 are likely to smoke.33 The 

high CH4 content of the gas stream routed to the completion combustion device, it suggests that there 

should not be smoke except in specific circumstances (e.g., energized fractures). The stream to be 

combusted may also contain liquids and solids that will also affect the potential for smoke. Soot can 

typically be eliminated by adding steam. Based on current industry trends in the design of completion 

combustion devices and in the decentralized nature of completions, virtually no completion combustion 

devices include steam assistance.34 

Reliable data for emission factors from flare operations during natural gas well completions are 

limited. Guidelines published in AP-42 for flare operations are based on tests from a mixture containing 

                                                            

33 See footnote 25. 

34 Ibid. 
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80 percent propylene and 20 percent propane.35 These emissions factors, however, are the best indication 

for secondary pollutants from flare operations currently available. These secondary emission factors are 

provided are provided in Table 4-7. Table 4-9 and 4-10 summarize estimated secondary emissions from 

oil wells based control scenarios using completion combustion devices. 

 

                                                            

35 Ibid.
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support 

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Table 4-6. Reduced Emission Completion and Combustion Emission Reductions and Cost Impa

Control Technology 

Emissions 

Reduced Per 

Completiona 

(short tons) 

Volume of Whole 

Gas Captured 

(Mcf/completion) 

Value of 

Whole Gas 

Captured 

($/completion) 

Annual 

Cost 

($) 

Cost of Control Per 

Completion 

(excluding gas savings) 

($/short ton) 

CH4 VOC CH4 VOC 

REC (100)b 8.75 7.33 899 $3,597 $13,459 $1,539 $1,837 REC (50/50)c 8.75 7.33 899 $3,597 $13,459 $769 $919 REC and Combustion device (100)b,d 9.23 7.73 899 $3,597 $17,183 $1,861 $2,222 REC and Combustion device (50/50)c,d 9.23 7.73 899 $3,597 $17,183 $930 $1,111 Completion Combustion (100)b 9.23 7.73 0 $0 $3,723 $403 $481 Completion Combustion (50/50)c 9.23 7.73 0 $0 $3,723 $202 $241 

a. Assumes 95% control. b. Scenario where 100 percent of the cost of control is attributed to methane and VOC. c. Scenario where 50 percent of the cost of control is attributed to methane and 50 percent is attributed to VOC. d. Control option that combines use of a REC and a combustion device to attain 95 percent control.
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Table 4-7. Emission Factors from Flare Operations from AP-42 Guidelines Table 13.4-1a

Pollutant Emission Factor 

(lb/106 Btu)

THCb 0.14 

CO 0.37 

NOx 0.068 

PMc 2.56e-3 

CO2

d

 60 

a. Based on combustion efficiency of 98 percent. 

b. Measured as CH4 equivalent. 

c. Soot in concentration values: nonsmoking flares, 0 micrograms per liter (μg/L); lightly 

smoking flares, 40 μg/L; average smoking flares, 177 μg/L; and heavily smoking flares, 

274 μg/L. 

d. Carbon dioxide is measured in kg CO2/MMBtu and is derived from the CO2 emission 

factor obtained from 40 CFR Part 98, subpart Y, Equation Y-2. 

4.5 Regulatory Options 

The REC pollution prevention approach would not result in emissions of CO, NOx, and 

particulate matter (PM) from the combustion of the completion gases in the completion combustion 

device, and would therefore be the preferred option. As discussed above, REC is only an option for 

reducing emissions from gas well completions/workovers with hydraulic fracturing. Taking this into 

consideration, the following regulatory alternatives were evaluated: 

 Regulatory Option 1. Require completion combustion devices for all hydraulically 

fractured oil well completions and recompletions; 

 Regulatory Option 2. Require REC for all hydraulically fractured oil well completions and 

recompletions; 

 Regulatory Option 3. Require REC and combustion operational standards for hydraulically 

fractured oil well completions and recompletions, with the exception of exploratory, and 

delineation wells; and 

 Regulatory Option 4. Require combustion operational standards for completions of exploratory 

and delineation wells. 

The following sections discuss these regulatory options. 

4.5.1 Evaluation of Regulatory Options 

Under Regulatory Option 1, nearly all of the natural gas emitted from the well during flowback 

would be destroyed by sending flowback gas through a combustion unit. Not only would this regulatory 
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option result in the destruction of a natural resource with no recovery of salable gas, it also would result 

in an increase in emissions of secondary pollutants (e.g., NOx, CO, etc.). Therefore, Regulatory Option 1 

was rejected. 

The second regulatory option would require RECs for all completions and recompletions of 

hydraulically fractured oil wells. As stated previously, RECs are not feasible for all well completions, 

such as exploratory wells, due to their distance from sales lines, etc. Further, RECs are also not 

technically feasible for each well at all times during completion and recompletion activities due to the 

variability of the pressure of produced gas and/or inert gas concentrations. Therefore, Regulatory Option 

2 was rejected. 

The third regulatory option was to require an operational standard consisting of a combination 

of REC and combustion for hydraulically fractured oil well completions. As discussed for Regulatory 

Option 2, RECs are not feasible for every well at all times during completion or recompletion activities 

due to variability of produced gas pressure and/or inert gas concentrations. In order to allow for 

wellhead owners and operators to continue to reduce emissions when RECs are not feasible due to well 

characteristics (e.g., wellhead pressure or inert gas concentrations), Regulatory Option 3 also allows for 

the use of a completion combustion device in combination with RECs. Under section 111(h)(2) of the 

CAA, the EPA can set an operational standard which represents the best system of continuous emission 

reduction, provided the following criteria are met: 

“(A) a pollutant or pollutants cannot be emitted through a conveyance designed and constructed 

to emit or capture such pollutant, or that any requirement for, or use of, such a conveyance would 

be inconsistent with any Federal, State, or local law, or 

(B) the application of measurement methodology to a particular class of sources is not 

practicable due to technological or economic limitations.” 

As discussed in section 4.4.3, emissions from a completion combustion device cannot be reliably 

measured or monitored to determine efficiency making an operational standard appropriate. Therefore, 

an operational standard under this regulatory option consists of a combination of REC and a completion 

combustion device to minimize the venting of natural gas and condensate vapors to the atmosphere, but 

allows venting in lieu of combustion for situations in which combustion would present safety hazards, 

other concerns, or for periods when the flowback gas is noncombustible due to high concentrations of 

inert gases. Sources would also be required, under this regulatory option, to maintain documentation of 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support 

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the overall duration of the completion event, duration of recovery using REC, duration of combustion, 

duration of venting, and specific reasons for venting in lieu of combustion. It was also evaluated whether 

Regulatory Option 3 should apply to all well completions, including exploratory and delineation wells. 

As discussed previously, one of the technical limitations of RECs is that they are not feasible 

for use at some wells due to their proximity to gas pipelines. Section 111(b)(2) of the CAA allows EPA 

to “...distinguish among classes, types, and sizes within categories of new sources for the purpose of 

establishing....” performance standards. Due to their distance from sales lines, and the relatively 

unknown characteristics of the formation, completion activities occurring at exploratory or delineation 

wells were considered to be a different “type” of activity than the types of completion activities 

occurring at all other gas wells. Therefore, two subcategories of completions were identified: 

Subcategory 1 wells are oil wells completed with hydraulic fracturing that do not fit the definition of 

exploratory or delineation wells. Subcategory 2 wells that meet the following definitions of exploratory 

or delineation wells: 

 Exploratory wells are wells outside known fields or the first well drilled in an oil or gas 

field where no other oil and gas production exists or 

 Delineation wells means a well drilled in order to determine the boundary of a field or 

producing reservoir. 

Based on this subcategorization, Regulatory Option 3 would apply to the Subcategory 1 wells 

and a fourth regulatory option was developed for Subcategory 2 wells. 

Regulatory Option 4 requires an operational standard for combustion for the Subcategory 2 

wells. As discussed above, a REC is not an option for exploratory and delineation wells based on their 

distance from sales lines. As with the Regulatory Option 3, a numerical limitation is not feasible. 

Therefore, this regulatory option requires an operational standard where emissions are minimized using 

a completion combustion device during completion activities at Subcategory 2 wells, with an allowance 

for venting in situations where combustion presents safety hazards or other concerns or for periods when 

the flowback gas is noncombustible due to high concentrations of inert gases. Consistent with 

Regulatory Option 3, records would be required to document the overall duration of the completion 

event, the duration of combustion, the duration of venting, and specific reasons for venting in lieu of 

combustion. 

In summary, Regulatory Options 1 and 2 were determined to be unreasonable due to 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support 

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undesirable loss of natural gas or technical feasibility and thereby rejected. Regulatory Options 3 and 4 

were determined to be applicable to oil wells and were evaluated further. 

4.5.2 Nationwide Impacts of Regulatory Options 

This section provides an analysis of the primary environmental impacts (i.e., emission 

reductions), cost impacts and secondary environmental impacts related to Regulatory Options 3 and 4 

which were selected as viable options for setting standards for completions and recompletions. 

4.5.2.1 Primary Environmental Impacts of Regulatory Options 

Regulatory Options 3 and 4 were selected as options for setting standards for completions and 

regulatory options as follows: 

 Regulatory Option 3. Operational standard for completions and recompletions with hydraulic 

fracturing for Subcategory 1 wells (i.e., wells which do not meet the definition of exploratory 

or delineation wells), which requires a combination of REC with combustion, but allows for 

venting during specified situations. 

 Regulatory Option 4. An operational standard for completions with hydraulic fracturing for 

exploratory and delineation wells (i.e., Subcategory 2 wells) which requires completion 

combustion devices with an allowance for venting during specified situations. 

The number of completions and recompletions that would be subject to the regulatory options 

listed above was presented in Table 4-3. From Table 4-4, it was estimated that there would be an 

estimated 13,806 hydraulically fractured developmental oil well completions and recompletions subject 

to Regulatory Option 3 in 2020 and an estimated 13,803 oil well completions and recompletions in 

2025. Regulatory Option 4 would apply to 870 uncontrolled exploratory oil well completions and 

recompletions with hydraulic fracturing in 2020 and 1,100 oil well completions and recompletions in 

2025. Because not all wells will have available infrastructure or will not otherwise be technically 

eligible to conduct RECs, we estimate that 50 percent of the uncontrolled subcategory 1 oil wells will be 

affected by the REC requirement and the other 50 percent will control emissions by combustion. 

Table 4-8 summarizes the nationwide emission reduction estimates for each regulatory option 

for the projected years 2020 and 2025. It was estimated that RECs in combination with the combustion 

of gas unsuitable for entering the gathering line, can achieve an overall 95 percent VOC reduction over 

the duration of the completion or recompletion operation. The 95 percent recovery was estimated based 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support 

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on 90 percent of flowback being captured to the sales line and assuming an additional 5 percent of the 

remaining flowback would be sent to the combustion device. Nationwide emission reductions were 

estimated by applying this 95 percent VOC reduction to the uncontrolled baseline emissions presented 

in Table 4-4. 

4.5.2.2 Cost Impacts 

The operational standards for Regulatory Options 3 and 4 include both REC and a completion 

combustion device, therefore the total incremental cost of the operational standard for Subcategory 1 

completions and for recompletions is estimated at around $17,183, which includes the costs in Table 4-6 

for the REC equipment and transportation in addition to the cost for the completion combustion device. 

Applying the cost for the combined REC with completion combustion device to the estimated 6,903 and 

combustion device only to the estimated 6,903 Subcategory 1 completions and recompletions in 

projected year 2020, the total nationwide cost was estimated to be approximately $119 million, which 

includes an estimated annual savings of approximately $25 million when natural gas savings are 

considered. Likewise, for projected year 2025, the cost for RECs with combustion device applied to 

6,902 Subcategory 1 completions and recompletions and the cost for combustion only applied to 6,902 

Subcategory 1 completions and recompletions, the total nationwide cost was estimated to be 

approximately $119 million, including annual savings estimated at around $25 million when natural gas 

savings are considered. For Regulatory Option 4, the costs for completion combustion devices presented 

in Table 4-6 would apply to Subcategory 2 completions. The cost per completion event was estimated to 

be $3,723. Applied to the 870 estimated Subcategory 2 completions and recompletions in projected year 

2020, the nationwide costs were estimated to be $3.2 million. 
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Table 4-8. Nationwide Emission and Cost Analysis of Regulatory Option 

Well Completion Category

Number of 

Sources 

Subject to 

NSPSa

Annual Cost 

Per 

Completion 

Eventb

($)

Nationwide Emission 

Reductionsc

(tpy)

Total Natio

($/y

Methane VOC without savings 

Base Year 2012 

Regulatory Option 3 

1. Development Oil Wellse 6,906 $17,183 63,766 53,398 $118,664,480 

 1. Development Oil Wellsf 6,906 $3,723 63,766 53,398 $25,714,478  Regulatory Option 4 

2. Exploratory/Delineation Oil Wells 545 $3,723 5,032 4,214 $2,029,306 Combined Option 3 and 4 14,357 NA 132,565 111,010 146,408,265 

Projected Year 2020

Regulatory Option 3 

1. Development Oil Wellse 6,903 $17,183 63,739 53,375 $118,614,014 

 1. Development Oil Wellsf 6,903 $3,723 63,739 53,375 $25,703,542  Regulatory Option 4 

2. Exploratory/Delineation Oil Wells 870 $3,723 8,037 6,730 $3,241,154 Combined Option 3 and 4 14,677 NA 135,516 113,481 147,558,710 

 Projected Year 2025

Regulatory Option 3 

1. Development Oil Wellse 6,902 $17,183 63,726 53,364 $118,588,789 

 1. Development Oil Wellsf 6,902 $3,723 63,726 53,364 $25,698,076  Regulatory Option 4 

2. Exploratory/Delineation Oil Wells 1,166 $3,723 10,770 9,019 $4,343,048 Combined Option 3 and 4 14,970 N/A 138,221 115,747 148,629,913 

a. Number of sources in each well completion category that are uncontrolled at baseline as presented in Table 4-3. b. Costs per event for Regulatory Options 3 is the cost of a REC combined with the cost of a completions device, and the cost for Opcombustion device only. c. Nationwide emission reductions calculated by applying the 95 percent emission reduction efficiency to the uncontrolled nationwidin Table 4-4. d. For developmental using a REC, assumes a cost savings for 899 Mcf gas recovered per completion event, valued at $4.00 Mcf, for $3,597 per event. e. These well completions are estimated to be eligible to conduct a REC (i.e., infrastructure and/or other well technical aspects suppo

f. These well completions are estimated to not be eligible to conduct a REC and must combust emissions.
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4.5.2.3 Secondary Impacts 

Regulatory Options 3 and 4 require some amount of combustion; therefore the estimated 

nationwide secondary impacts are a direct result of combusting all or partial flowback emissions. 

Although, it is understood that the volume of gas captured, combusted and vented may vary 

significantly depending on well characteristics and flowback composition, for the purpose of estimating 

secondary impacts for Regulatory Options 3 and 4, it was assumed that 90 percent of flowback is 

captured and an additional 5 percent of the remaining gas is combusted. For Subcategory 1 oil well 

completions and recompletions with hydraulic fracturing, it is assumed around 50 Mcf (5 percent of 999 

Mcf) of natural gas is combusted on a per well basis when a REC is performed. For Regulatory Option 

3 for Subcategory 1 oil wells where combustion is used for control and for Regulatory Option 4 for 

Subcategory 2 oil well completions and recompletions with hydraulic fracturing, it is assumed that 95 

percent (or 949 Mcf) of flowback emissions are combusted by the combustion device. The ns of 

pollutant emissions per completion event was estimated assuming 1,089.3 Btu/scf saturated gross 

heating value of the "raw" natural gas and applying the AP-42 emissions factors listed in Table 4-7. 

For the projected year 2020, for Subcategory 1 well completions and recompletions controlled by 

a REC combined with a combustion device, it is estimated 0.002 tons of NOx are produced per event. 

This is based on assumptions that 5 percent of the flowback gas is combusted by the combustion device. 

For subcategory 1 and subcategory 2 well completions controlled with a combustion device alone, it is 

estimated 0.37 tons of NOx are produced in secondary emissions per event. This is based on the 

assumption 95 percent of flowback gas is combusted by the combustion device. Based on the estimated 

number of completions and recompletions for projected year 2020, the proposed regulatory options are 

estimated to produce around 300 tons of NOx in secondary emissions nationwide from controlling all or 

partial flowback by combustion. Table 4-9 summarizes the estimated secondary emissions of the selected 

regulatory options for projected year 2020 and Table 4-10 summarizes the estimated secondary emissions 

of the selected regulatory options for projected year 2025. 

 
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Table 4-9. Nationwide Secondary Impacts of Selected Regulatory Options for Projected Ye

Pollutant

Regulatory Option 3b,c Regulatory Option 4

1. Developmental Oil Well - REC 1. Developmental Oil Well - Combustion 

2. Exploratory/Delineati

Well

Emissions per 

Completion 

Event 

(tons) 

Nationwide 

Secondary 

Emissions 

(tpy) 

Emissions per 

Completion Event 

(tons) 

Nationwide 

Secondary 

Emissions 

 (tpy)

Emissions per 

Completion 

Event 

(tons) 

Nation

Secon

Emis

(tp

THC 0.004 26 0.076 526 0.076 6CO 0.010 69 0.201 1,390 0.201 17NOx 0.002 13 0.037 255 0.037 3PM 0.000 0 0.001 9 0.001 1 CO2 3.599 24,846 71.987 496,924 71.987 62,6

a. Nationwide impacts are based on AP-42 Emission Guidelines for Industrial Flares as outlined in Table 4-7. As such, these emissions 

minimum level of secondary emissions expected. b. The REC operational standard (Regulatory Options 3 REC) combines REC and combustion is assumed to capture 90 percent of flowremaining flowback is assumed to be combusted by the combustion device. Therefore, it is estimated 50 Mcf is combusted per completassumes there are 6,903 developmental oil well completions and recompletions using this control scenario. c. Assumes 949 Mcf of natural gas is sent to the combustion unit and 902 Mcf is combusted per completion. This analysis assumes 6,90completions and recompletions exploratory wells fall into this category. d. Assumes 949 Mcf of natural gas is sent to the combustion unit and 902 Mcf is combusted per completion. This analysis assumes 870 category. 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support 

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Table 4-10. Nationwide Secondary Impacts of Selected Regulatory Options for Projected Ye

Pollutant

Regulatory Option 3b,c Regulatory Option 4

1. Developmental Oil Well - REC 1. Developmental Oil Well - Combustion 

2. Exploratory/Delineati

Well

Emissions per 

Completion 

Event 

(tons) 

Nationwide 

Secondary 

Emissions 

(tpy) 

Emissions per 

Completion Event 

(tons) 

Nationwide 

Secondary 

Emissions 

 (tpy)

Emissions per 

Completion 

Event 

(tons) 

Nation

Secon

Emis

(tp

THC 0.004 26 0.076 526 0.076 8CO 0.010 69 0.201 1,390 0.201 22NOx 0.002 13 0.037 255 0.037 4PM 0.000 0 0.001 9 0.001 1 CO2 3.599 24,843 71.987 496,852 71.987 79,

a. Nationwide impacts are based on AP-42 Emission Guidelines for Industrial Flares as outlined in Table 4-7. As such, these emissions 

minimum level of secondary emissions expected. b. The REC operational standard (Regulatory Options 3 REC) combines REC and combustion is assumed to capture 90 percent of flowremaining flowback is assumed to be combusted by the combustion device. Therefore, it is estimated 50 Mcf is combusted per completassumes there are 6,902 developmental oil well completions and recompletions using this control scenario. c. Assumes 949 Mcf of natural gas is sent to the combustion unit and 902 Mcf is combusted per completion. This analysis assumes 6,90completions and recompletions exploratory wells fall into this category. d. Assumes 949 Mcf of natural gas is sent to the combustion unit and 902 Mcf is combusted per completion. This analysis assumes 1,10this category. 
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4.6 Comparison of Flowback Emissions Estimate Methodology to Measured Emissions 

from UT-Austin – Allen et al. Study36 

A limited number of measurements have been conducted on hydraulically fractured oil well 

completions, in Allen et al. Due to the small sample size, these data were not used to estimate nationwide 

emissions from oil well completions in this analysis. However, data from Allen et al can be used to assess 

the emissions estimation methodology described in Section 4.2.2 above. 

In comments on the white paper on this emissions source, Dr. Allen compared the “measured 

potential emissions” for oil well completions from Allen et al. to an estimate of potential well completion 

emissions calculated using data from the first month of gas production for those wells. For three of the 

four wells included in his assessment, the measured potential emissions from Allen et al. compared very 

well with emissions calculated using the average daily gas production for the first month of production and 

the flowback duration of each well, with ratios of measured potential emissions to estimated potential 

emissions based on duration and gas production ranging from 1.05 to 1.4. A fourth well included in the 

assessment had measured potential emissions that were 31 times higher than the potential emissions 

measured based on initial production and flowback. There was some uncertainty with the flowback 

duration of the completion event at the fourth well, as described in Allen et al. Dr. Allen noted in his 

comments the method led to reasonable results for three wells, but that the fourth well demonstrates that 

consistent application of the method may be difficult. 

In the EPA’s analysis, the methodology to develop an average estimate of potential emissions for 

hydraulically fractured oil well completions in the U.S. uses data on gas production for each oil well 

completed in 2012 during the first month of operation from the Drilling Info database. Average daily 

production in the first month of operation was then multiplied by an estimate of the average number of 

days of flowback (3 days) to calculate potential well completion emissions for each well in the data set. 

The values for potential emissions per completion for all of the wells were then averaged. The EPA 

expects that like other oil and gas emissions sources, oil well completions may have a wide range of 

emissions. The EPA believes that the emissions rate it calculated in section 4.2.2 represents a reasonable 

estimate of average, uncontrolled emissions.

                                                            

36 UT Austin - Allen et al., Measurements of methane emissions at natural gas production sites in the United States. PNAS USA 

(110:17778-17773) September 2013.
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Table 4-11. Comparison of Flowback Emissions Estimate Methodology to Measured Emission

UT Austin - Allen et al. Study 

Well ID GOR (scf/bbl) 

First Month 

Gas Production 

Rate 

(Mcf/day)a

Duration of 

Flowback 

(days) 

Gas Production 

Rate x Duration 

of Flowback 

(Mcf) 

Estimated Potential 

CH4 Emissionsb

(Mcf/completion) 

Measured 

Potential CH4 

Emissionsa 

 (Mcf) 

GC-1 4,046 3,000 3.13 9,375 4,381 5,000 GC-2 4,267 2,700 3.17 8,550 3,995 4,250 GC-6 30,703 6,100 6.83 41,683 19,479 12,200 GC-7 3,508 1,500 4.50 6,750 3,154 4,320 

a. From Allen, et al. (2013), Supporting Information, Table S1-6. b. Allen et al. notes that there was ambiguity in the report data as to the duration of this flowback period. This well had an initial flowback for 28 hours. After 28 hours, the flow was directed to a separator and the gas from the separator was then sent to sales and a flare. In this c

duration of the flowback, as reported by the company, since gas had begun to go to sales. The study team reported emissions from this flofrom the flare, which occurred after the initial 28 hours of flowback.
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5.0 FUGITIVE EMISSIONS STANDARDS 

Fugitive emissions from components in the oil and natural gas source category are a source of 

CH4 and VOC emissions. This chapter explains the causes for these fugitive emissions, and provides 

CH4 and VOC emission estimates for “model” facilities in the production and transmission and storage 

segments. In addition, nationwide equipment fugitive emission estimates from new sources are 

estimated. Programs that are designed to reduce fugitive emissions are explained, along with costs, 

emission reductions, and secondary impacts. Finally, this chapter discusses considerations in developing 

regulatory alternatives for fugitive emissions from equipment.

5.1 Fugitive Emissions Description 

There are several potential sources of fugitive emissions throughout the oil and natural gas 

source category. Fugitive emissions occur when connection points are not fitted properly or when seals 

and gaskets start to deteriorate. Changes in pressure and pressure or mechanical stresses can also cause 

components or equipment to emit fugitive emissions. Potential sources of fugitive emissions include 

agitator seals, connectors, pump diaphragms, flanges, instruments, meters, open-ended lines (OELs), 

pressure relief devices, pump seals, valves or improperly controlled liquid storage tanks. These fugitive 

emissions do not include devices that vent as part of normal operations, such as gas driven pneumatic 

controllers or gas driven pneumatic pumps. 

For the purposes of the analysis and regulatory evaluation of fugitive emissions from 

components and equipment, we determined the need to differentiate between the current definition of 

"equipment" in the rule37 and the intended definition for the purposes of addressing fugitive emissions. 

Therefore, we have defined a new term, "fugitive emissions component" as the focus of the requirements 

for fugitive emissions. Fugitive emissions component means any component that has the potential to 

emit fugitive emissions of methane or VOC, 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 a gas-driven pneumatic controller or a 

                                                            

37 The Oil and Natural Gas Sector NSPS (40 CFR 60, subpart OOOO) specifically defines “equipment” relative to standards 

for equipment leaks of VOC from onshore natural gas processing plants. As used in this chapter, the term “equipment” is 

used in a broader context and is not meant to be limited by the manner in which the term is currently used in subpart OOOO. 
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gas-driven pump, are not fugitive emissions components, insofar as the gas discharged from the device’s 

vent is not considered a fugitive emission. Emissions originating from sites other than the vent, such as 

the seals around the bellows of a diaphragm pump, would be considered fugitive emissions. 

 In April of 2014, the EPA published a white paper38 which summarized the EPA’s current 

understanding of CH4 and VOC fugitive emissions at onshore oil and natural gas production, processing 

and transmission and storage facilities. The white paper also outlined the EPA’s understanding of the 

available mitigation techniques (practices and equipment) available to reduce these emissions along with 

the cost and emission reduction potential of these practices and technologies. The 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 (e.g., organic vapor analyzer (OVA), flame ionization 

detector, flow measurement devices). In addition to EPA Method 21 analyzers, several studies 

conducted fugitive emission surveys using optical gas imaging (OGI) in conjunction with portable 

Method 21 analyzers and gas chromatograph equipment to measure individual VOC and HAP 

compounds. These studies provided emission estimates in the form of component or equipment emission 

factors or emission estimates by facility. Fugitive emission estimates for CH4 and VOC ranged from 1.4 

to 32 tons per year (tpy) and 0.4 to 10 tpy, respectively for oil and natural gas production sites. Even 

though there is a wide variation in the potential CH4 and VOC emissions, the studies showed that there 

are economical options for reducing these emissions. 

5.2 Fugitive Emissions Data and Emissions Factors 

5.2.1 Summary of Major Studies and Emission Factors 

The Oil and Natural Gas Sector Leaks white paper provided a summary of fugitive emission 

studies at oil and natural gas production and compressor stations. In the evaluation of the emissions and 

emission reduction options for equipment leaks, many of these studies in the white paper were 

consulted. Table 5-1 presents a list of the studies consulted along with an indication of the type of 

information contained in the study. 

5.2.2 Model Plants 

Facilities in the oil and natural gas source category can consist of a variety of combinations of 

process equipment and other components. This is particularly true in the production segment of the 

                                                            

38 U.S. EPA. Oil and Natural Gas Sector Leaks, OAQPS. Research Triangle Park, NC. April 2014. Available at 

http://www.epa.gov/airquality/oilandgas/2014papers/20140415leaks.pdf.
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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 emissions from leaking fugitive 

emissions components, a model plant approach was used. The following sections discuss the creation of 

these model plants. 

Information related to fugitive emissions components counts was obtained from the GRI/EPA 

natural gas industry study39 and other sources. The GRI/EPA document provided average fugitive 

emissions component counts for natural gas production, natural gas processing, natural gas transmission 

and natural gas storage including; valves, connectors, OELs, and pressure relief valves (PRVs). 

Although these counts do not include all potential fugitive emissions components, as described in the 

definition, these were the best available data as to counts for fugitive emissions components. These 

average counts were used to develop model plants for well sites, and compressor stations (including 

those at gathering and boosting stations, transmission stations, and storage facilities). These fugitive 

emissions component counts are consistent with those contained in the EPA’s Inventory of U.S. 

Greenhouse Gas Emissions and Sinks, and in the EPA’s analysis to estimate CH4 emissions conducted 

in support of the GHG Mandatory Reporting Rule (subpart W), which was published in the Federal 

Register (FR) on November 30, 2010 (75 FR 74458). As we have emission factors for only a subset of 

the components which are noted as possible sources for fugitive emissions, the model plants and 

subsequent emission estimates presented are believed to be lower than the emissions profile for the 

entire set of components that would be considered for a representative model plant. These model plants 

are discussed in the following sections. 

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

Report Name Affiliation Year of 

Report 

Activity 

Factor(s) 

Emissions 

Data 

Control 

Options 

Protocol for Equipment Leak 

Emission Estimatesa EPA 1995 None X X 

CH4 Emissions from the Natural 

Gas Industry: Equipment Leaksb GRI/EPA 1996 Nationwide X X 

GHG Reporting Programc EPA 2013 Facility X 

Inventory of GHG Emissions 

and Sinks: 1990-2013d EPA 2015 Regional X 

                                                            

39 Gas Research Institute (GRI)/U.S. EPA. Research and Development, Methane Emissions from the Natural Gas Industry, 

Volume 8: Equipment Leaks. June 1996 (EPA-600/R-96-080h). 
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Report Name Affiliation Year of 

Report 

Activity 

Factor(s) 

Emissions 

Data 

Control 

Options 

Measurements of CH4

Emissions at Natural Gas 

Production Sites in the United 

States (U.S.)e

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, 

Coloradog

ARCADIS/Sage 

Environmental 

Consulting/EPA 

2012 Colorado X X 

Quantifying Cost-Effectiveness 

of Systematic Leak Detection 

and Repair (LDAR) Programs 

Using Infrared (IR) 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 CH4

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 CH4

Losses at Four Gas Processing 

Plantsk

Clearstone 

Engineering, Ltd. 2002 

4 gas 

processing 

plants 

X X 

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, 7 

gathering 

stations 

X X 

a. U.S. EPA, 1995. Protocol for Equipment Leak Emission Estimates. OAQPS. Research Triangle Park, NC. 

November 1995. EPA-453/R-95-017. Available at http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf.

b. GRI/U.S. EPA. Research and Development, Methane Emissions from the Natural Gas Industry, Volume 8: 

Equipment Leaks. June 1996 (EPA-600/R-96-080h). 

c. U.S. EPA. 2013b. Petroleum and Natural Gas Systems: 2012 Data Summary. GHG Reporting Program. October 

2013. 

d. U.S. EPA.2013a. 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. 2013. Measurements of methane emissions at natural gas production sites in the U.S.. 

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.
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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 LDAR Programs using IR 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. 2012. 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. 

5.2.2.1 Oil and Gas Production 

Oil and natural gas production practices and equipment vary from site-to-site. 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 pad. 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 that have associated components that 

may be sources of fugitive emissions (including piping and associated components, compressors, 

generators, separators, storage vessels, and 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. 

 Equipment (e.g., valves, pumps, PRVs, etc.) count data from the GRI/EPA report were used to 

calculate the average counts of fugitive emissions components located at a natural gas well site. The 

types of production equipment located at these well site include: gas wellheads, separators, 

meters/piping, heaters, and dehydrators. The types of components that are associated with this 

production equipment include: valves, connectors, OELs, and PRVs. Component counts for each of the 

production equipment items were calculated using the average component counts for onshore production 

equipment in the Eastern U.S and the Western U.S. from the EPA/GRI report. 

For oil wells, component counts were obtained from an American Petroleum Institute (API) 

workbook40. The types of oil well production equipment include: oil well heads, separators, headers and 

heater/treaters. Fugitive emissions components counts for these production equipment types were 

                                                            

40 API Workbook 4638, 1996. 
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estimated using the average component counts for onshore production equipment in the Eastern U.S and 

the Western U.S. from the EPA/GRI report. 

A model plant was developed using the average number of wells associated with a well site using 

data from the Drillinginfo HPDI® database41. EPA estimated the number of wells on a typical well site 

using a spatial analysis of producing crude oil and natural gas wells from the DrillingInfo HPDI 

database42. 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 well site. 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.43 

 The HPDI well and production data used to estimate the average number of well co-located 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, the 

two wells were assumed to be co-located. This algorithm progressed county by county across the U.S. 

where oil and natural gas 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 wells 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. While it was not 

possible to visually inspect every site in the U.S. linked to a 2012 completion or recompletion, as they 

numbered greater than 20,000, 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. 

                                                            

41 Drilling Information, Inc. 2011. DI Desktop. 2011 Production Information Database. 42 Ibid. 43 See the website <http://www.r-project.org/> for more information on R.
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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 5-2 shows the high-level results of these analyses. 

Table 5-2. Estimated Average Number of Wells per Well Site in 2012

Assumed Well 

Site Size 

No. of 

Well Sites 

No. of 

Wells at Sites 

Average of 

Wells Per Site 

One Acre 29,213 50,559 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 X masks variation by basins and well 

types. Table 5-3 presents more detail along these dimensions for the assumed two-acre well site. 

Table 5-3. 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) 

HPDI Basin 

No. 

Of 

Sites 

Oil Well 

Completions 

Natural Gas Well

Completions Total 

HF Not 

HF All HF Not HF All 

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 

   
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HPDI Basin 

No. 

Of 

Sites 

Oil Well 

Completions 

Natural Gas Well

Completions Total 

HF Not 

HF All HF Not HF All 

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 

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 
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HPDI Basin 

No. 

Of 

Sites 

Oil Well 

Completions 

Natural Gas Well

Completions Total 

HF Not 

HF All HF Not HF All 

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 

What is evident in Table 5.3 is 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 co-located 

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 national-level, 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 judgement, we decided to use the two-acre 

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 2.00. 

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 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. 
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Alternatively, the assumed two acre 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 longitudes 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. 

For natural gas production well sites, the model plant was developed using the average fugitive 

emissions components counts for gas production data from the GRI/EPA report. The average component 

count for a gas well was estimated by weighting the average of component 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 production well site component counts were calculated by multiplying the average well 

component 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 production equipment items were calculated 

using the average component counts for onshore 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 component counts by the component count per production 

equipment and rounding to the nearest integer. A summary of the fugitive emissions component counts 

for natural gas production well sites is presented in Table 5-4. 

For oil production well sites, the model plant was developed using component counts from an 

API workbook and component count data from the GRI/EPA study. The average component 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 production well site component counts were calculated by multiplying the average well production 

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 component counts by the component count 

per production equipment and rounding up to the nearest integer. A summary of the fugitive emissions 

component counts for oil production well sites is presented in Table 5-5. 

Baseline model plant emissions for the natural gas and oil production well sites were calculated 

using the fugitive emissions component counts and the component oil and natural gas production 

emission factors from AP-4244. Annual emissions were calculated assuming 8,760 hours of operation 

                                                            

44 U.S. EPA, Protocol for Equipment Leak Emission Estimates, Table 2-4, November 1995. (EPA-453/R-95-017) 
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each year. The emissions factors are provided for total organic compounds (TOC) and include nonVOCs such as CH4 and ethane. The emission factors used to estimate the new source emissions from the 

production segment (e.g., oil production well sites, natural gas production well sites, gathering and 

boosting stations) are presented in Table 5-6. 

Emissions of VOC were calculated using weight ratios for VOC/TOC as described in the 2011 

Gas Composition Memorandum developed for the 2012 NSPS45. A summary of the fugitive emissions 

component counts, average CH4 emissions factors, CH4 emissions and VOC emissions for natural gas 

and oil production well sites is provided in Tables 5-7 and 5-8, respectively. The average fugitive 

emissions from a gas well model plant were determined to be 4.54 tpy of CH4 and 1.26 tpy of VOC and 

the average fugitive emissions from an oil well model plant was determined to be 1.09 tpy of CH4 and 

0.30 tpy of VOC. These emissions were used to estimate the potential emission reductions and cost of 

control of a fugitive emissions reduction program. 

The estimates presented here were developed using average emission factors for typical 

components of the process equipment present at well sites, and average values for equipment counts per 

well site. Many studies have shown a skewed distribution for emissions related to leaks, where a 

majority of emissions come from a minority of sources. This means that some sources have emissions 

significantly higher than would be calculated using average emission factors and average component 

types. Sources included in the subset of a data set that contributes to the majority of emissions are 

sometimes referred to as “gross emitters” or “super emitters.” These gross emitters have been observed 

among groups of components within a site, among groups of entire facilities, and within data sets of 

components of the same type across a number of sites or facilities. 

Of the data sources presented in the white paper, all of the sources with full data sets available 

exhibited skewed distributions, including the Allen et al. (2013) data set on well site fugitives, and the 

ERG City of Fort Worth study, in which 20% of the surveyed well sites accounted for 80% of total 

emissions. Both studies by Clearstone Engineering, Ltd. showed skewed distributions of leak emissions 

at processing plants, and the two mobile measurement studies observed skewed distributions at well 

sites. Since publication of the white paper, additional data have become available on fugitive emissions 

at well sites, including reporting year 2013 data from GHGRP, which included onshore production 

fugitive emissions of 8,719,385 tons CO2e of methane from reporters. 

                                                            

45 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 28, 2011.
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5.2.2.2 Gathering and Boosting Station 

Gathering and boosting stations are sites that collect oil and natural gas from well sites and direct 

them to the natural gas processing plants. These stations have similar production equipment (including 

separators, meters, piping, compressors, in-line heaters, dehydrators and other production 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 fugitive emissions component counts for onshore 

production from the GRI/EPA study. The average component count for a gathering and boosting station 

was estimated by weighting the average of component counts for the Eastern and Western U.S. data sets 

for onshore 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 onshore 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 a Chapter 8 of 

this document. A summary of the fugitive emissions component counts for oil and gas gathering and 

boosting stations are presented in Table 5-9. 

Baseline emissions were calculated using the component counts and the CH4 emission factors for 

oil and natural gas production (See Table A-3). The baseline emissions for gathering and boosting 

stations are summarized in Table 5-10. The average fugitive emissions from a gathering and boosting 

station were determined to be 35.1 tpy of CH4 and 9.77 tpy of VOC. These emissions were used to 

estimate the potential emission reductions and cost of control of a fugitive emissions reduction program. 

Since publication of the white paper, additional data have become available on fugitive 

emissions from compressor stations, including data from the Measurements of Methane Emissions from 

Natural Gas Gathering Facilities and Processing Plants: Measurement Results study published in 2015.46

This study measured facility-level emissions, including fugitive emissions, at gathering and processing 

facilities. Data sets for both facility types had skewed distributions. In the study data sets, 30% of 

gathering facilities contributed 80% of the total emissions, and gathering facilities emitted, on average 

yielded higher emissions than would be calculated with the factors used in this analysis. 

                                                            

46 Mitchell, Austin L. et al. Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing 

Plants: Measurement Results. Environ. Sci.Technol. 2015, 2119-3227.
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Table 5-4. Average Fugitive Emissions Component Count for Gas Production Well Site Mod

Production Equipment 

Model Plant 

Production 

Equipment 

Counts 

Average Component Count Per Unit of 

Production Equipmenta Average Component Count 

Valves Connectors OELs PRVs Valves Connectors O

Gas Wellheads 2 9 37 1 0 19 74 Separators 2 22 68 4 1 43 137 Meters/Piping 1 13 48 0 0 13 48 In-Line Heaters 1 14 65 2 1 14 65 Dehydrators 1 24 90 2 2 24 90 

Total 113 414 

Rounded up Total 114 414 

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

Table 5-5. Average Fugitive Emissions Component Count for Oil Production Well Site Mode

Production Equipment 

Model Plant 

Production 

Equipment 

Counts 

Average Component Count Per Unit of 

Production Equipmenta Average Component Count 

Valves Connectors OELs PRVs Valves Connectors O

Oil Wellheads 2 5 18 0 0 10 36 Separators 1 6 22 0 0 6 22 Headers 1 5 14 0 0 5 14 Heater/treaters 1 8 32 0 0 8 32 

Total 29 104 

Rounded up Total 29 104 

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
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Table 5-6. Oil and Gas Production Operations Average Emissions Factors 

Component Type Component 

Service 

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) 

Table 5-7. Estimated Fugitive Emission Estimate for Natural Gas Production Well Site Model Plant 

Natural Gas Well 

Site Model Plant 

Component 

Model Plant 

Component 

Counta

Uncontrolled 

Emission Factorb 

(kg/hr/comp) 

Uncontrolled Emissions 

(tpy) 

CH4

c VOCd

Valves 114 0.0045 3.442 0.957 

Connectors 414 0.0002 0.555 0.154 

OELs 14 0.002 0.188 0.052 

PRVs 6 0.0088 0.354 0.098 

Total 4.54 1.26 

a

 Fugitive emissions 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. CH4 emissions calculated using 0.695 weight ratio for CH4/TOC obtained from gas composition memorandum. 

d. VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from gas composition memorandum. 

Table 5-8. Estimated Fugitive Emission Estimate for Oil Production Well Site Model Plant 

Natural Gas Well 

Site Model Plant 

Component 

Model Plant 

Component 

Counta

Uncontrolled 

Emission Factorb 

(kg/hr/comp) 

Uncontrolled Emissions 

(tpy) 

CH4

c VOCd

Valves 29 0.0045 0.876 0.243 

Connectors 104 0.0002 0.140 0.039 

OELs 1 0.002 0.013 0.004 

PRVs 1 0.0088 0.059 0.016 

Total 1.09 0.302 

a. Fugitive emissions 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. CH4 emissions calculated using 0.695 weight ratio for CH4/TOC obtained from gas composition memorandum. 

d. VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from gas composition memorandum. 
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Table 5-9. Average Fugitive Emissions Component Count for Gathering and Boosting Station M

Production Equipment 

Model Plant 

Production 

Equipment 

Counts 

Average Component Count Per Unit of 

Production Equipmenta Average Component Cou

Valves Connectors OELs PRVs Valves Connectors 

Separators 11 22 68 4 1 242 748 Meters/Piping 7 13 48 0 0 91 336 Gathering Compressors 5 71 175 3 4 355 875 In-Line Heaters 7 14 65 2 1 98 455 Dehydrators 5 24 90 2 2 120 450 

Total 906 2,864 

Rounded up Total 906 2,864 

a. Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-4 and 4-7, June 1996

Table 5-10. Estimated Fugitive Emission Estimate Gathering and Boosting Station Model 

Gathering and 

Boosting Station 

Model Plant 

Component 

Model Plant 

Component Count 

Uncontrolled 

Emission Factora 

(kg/hr/comp) 

Uncontrolled Emission

(tpy) 

CH4b VOC

Valves 906 0.0045 27.35 7.60Connectors 2,864 0.0002 3.84 1.06OELs 83 0.002 1.11 0.31PRVs 48 0.0088 2.83 0.78

Total 35.1 9.77 

a. TOC emission factors obtained from Table 2-4 for the EPA Equipment Leaks Protocol for components in gas serb. Methane emissions calculated using 0.695 weight ratio for CH4/TOC obtained from gas composition memorandu

c. VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from gas composition memorandum
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5.2.2.3 Natural Gas Transmission and Storage 

Natural gas transmission and storage stations are facilities that use compressors that move natural 

gas at elevated pressure from production fields or natural gas processing facilities, in transmission 

pipelines, to natural gas distribution pipelines, or into storage. In addition, transmission stations may 

include production equipment for liquids separation, natural gas dehydration, and tanks for the storage of 

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

facilities are included in the onshore natural gas processing segment and are excluded from this segment. 

The segments include fugitive emissions from components related to inlet and outlet pipelines, meter runs, 

dehydrators, and other piping located at the compressor building for transmission and storage stations, and 

injection/withdrawal components associated with the injection/withdrawal well piping at storage stations. 

This industry segment also includes emissions from compressor related components, but does not include 

emissions from compressors or gathering and boosting stations. Fugitive emissions component counts and 

CH4 emission factors were obtained from the EPA/GRI study. A summary of the fugitive emissions 

component counts, component emission factors and baseline CH4 and VOC emissions for transmission 

and storage model plants are presented in Table 5-11. The average fugitive emissions for transmission 

stations were determined to be 62.4 tpy of CH4 and 1.73 tpy of VOC and 164.4 tpy of CH4 and 4.55 tpy of 

VOC for storage facilities. These emissions were used to estimate the potential emission reductions and 

cost of control of a fugitive emissions reduction program. 

Table 5-11. Estimated Fugitive Emission Estimate for Oil and Natural Gas Transmission and 

Storage Model Plant 

Component 

Model Plant 

Component 

Counta

Component CH4

Emission Factora

(Mscf/year/component) 

CH4

Emissionsb

(tpy) 

VOC 

Emissionsc

(tpy) 

Transmission Facility 

Valve 673 0.867 12.1 0.366 

Control Valve 31 8 5.2 0.143 

Connectors 3,068 0.147 9.4 0.260 

OEL 51 11.2 11.9 0.329 

PRV 14 6.2 1.8 0.050 

Site Blowdown OEL 4 264 22.0 0.608 

Total 62.4 1.73 

Storage Facility 

Valve 1,868 0.867 33.7 0.933 

Connector 5,571 0.147 17.0 0.472 

OEL 353 11.2 82.3 2.277 

PRV 66 6.2 8.52 0.236 

Site Blowdown OEL 4 264 22.0 0.608 

Valve (Inj/With) 30 0.918 0.57 0.016 

Connector (Inj/With) 89 0.125 0.23 0.006 
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Component 

Model Plant 

Component 

Counta

Component CH4

Emission Factora

(Mscf/year/component) 

CH4

Emissionsb

(tpy) 

VOC 

Emissionsc

(tpy) 

OEL (Inj/With) 7 0.237 0.03 0.001 

PRV (Inj/With) 1 1.464 0.03 0.001 

Total 164.4 4.55 

a. Component counts and CH4 emission factors for non-compressor related components obtained from EPA/GRI, Methane 

Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-17 and 4-24, June 1996. (EPA-600/R-96-080h)

b. Methane emissions calculated by multiplying the model plant component count by the component CH4 emission factor and 

converting to tons using the conversion factor 0.02082 tons CH4/Mscf CH4. 

c. VOC emissions calculated using 0.0277 weight ratio for VOC/CH4 obtained from Gas Composition memorandum. 

5.3 Nationwide Emissions from New Sources 

5.3.1 Overview of Approach 

Similar to the approach used to calculate emissions from well site and compressor station model 

plants, nationwide emissions were calculated by using the model plant approach for estimating emissions. 

Baseline model plant emissions for the oil and natural gas production and transmission and storage 

segments were calculated using the equipment and fugitive emissions component counts and the 

representative gas service emission factors. Emissions were estimated using the EPA Protocol for 

Equipment Leak Emission Estimates which provided TOC emission factors for production sources (well 

sites, gathering and boosting) and the GRI/EPA study which provided CH4 emission factors for 

transmission and storage facilities. The VOC emissions were calculated using weight fractions provided in 

the gas composition memorandum.

5.3.2 Activity Data 

Data from oil and natural gas technical documents and inventories were used to estimate the 

number of new sources for each of the oil and natural gas segments. Information from the Drillinginfo 

HPDI® database, GHG Inventory were used to estimate the number of new well sites, gathering and 

boosting stations, and transmission and storage facilities. A summary of the steps used to estimate the new 

sources for each of the oil and gas segments is presented in the following sections. 

5.3.2.1 Well Sites 

The Drillinginfo database provided the information on the number of oil and natural gas wells 

completed or recompleted in the 2012 in the U.S. The total number of new natural gas well completions, 

both conventional and fractured was determined to be 8,456. From this number of wells, we subtracted 

wells that were assumed to be covered by State leak regulations as of the effective date of the revised 

NSPS. Based on our research, four states have recently enacted State leak regulations. Colorado, Ohio, 

Wyoming and Utah. Below is a brief discussion of these state regulations: 
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 Colorado: Effective on April 14, 2014, requires well production facilities and natural gas 

compression station owners/operators to inspect components for leaks using an approved 

instrument monitoring method (AIMM). This LDAR program began as early as January 1, 2015 

with inspection frequency varying based on the amount of fugitive VOC emissions identified (i.e., 

0-6 tpy - one-time, 6-12 tpy -annually, 12-50 tpy -quarterly, or >50 tpy -monthly). Inspections can 

be conducted using Method 21. AVO and an infra-red camera may also be used for monitoring 

where a leak is defined as any detectable emissions that are not associated with normal equipment 

operation (e.g. pneumatic device actuation)47 

 Ohio: On May 19, 2014 Ohio EPA approved two types of oil and gas well-site production 

operations (small flares and large flares) and high volume horizontal hydraulic fracturing general 

permits for facilities that emit less than 1 ton per year of any toxic air contaminant (not including 

HAP emitting sources that are subject to MACT HH). Operators are required to develop and 

implement a site-specific LDAR program for ancillary equipment (e.g. vent, compressor, PRD, 

flange, etc.) that requires monitoring using a FLIR camera or Method 21. Quarterly monitoring is 

required for the first year and varies after that depending on performance. 48 

 Wyoming: On June 30, 2015, Wyoming Department of environmental Quality issued regulations 

for existing (as of January 1, 2014) PAD and single-well oil and gas production facilities that are 

located in the Upper Green River Basin. The rule regulates fugitive emissions from PAD and 

single-well facilities or sources, and compressor stations with fugitive emissions greater than or 

equal to 4 tons per year of VOC and requires owner/operators to develop and implement an LDAR 

protocol by January 1, 2017. Fugitive emissions monitoring can be conducted using a combination 

of Method 21, OGI, other instrument based technologies, or audio-visual-olfactory (AVO) 

inspections. However, an LDAR protocol consisting of only AVO inspections does not meet the 

requirements of the rule - at least one quarterly evaluation must be done using Method 21, OGI, or 

other instrument based technology. The rule requires quarterly monitoring of control equipment, 

systems, and devices (e.g. reboiler overhead condensers, storage tanks, vent lines, valves, 

connectors, etc.).49

 Utah: On June 5, 2014, Utah Department of Environmental Quality approved a “General Approval 

                                                            

47 Colorado regulations available at https://www.colorado.gov/pacific/sites/default/files/5-CCR-1001-9_0.pdf. 48  Ohio regulations available at http://www.epa.ohio.gov/Portals/27/oil%20and%20gas/GP12.1_PTIOA20140403final.pdf 

http://epa.ohio.gov/dapc/genpermit/genpermits.aspx#127854016-available-permits. 49 Wyoming regulations are available at http://soswy.state.wy.us/Rules/RULES/9868.pdf.
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Order for a Crude Oil and Natural Gas Well Site and/or Tank Battery” on June 5, 2014. This GAO 

requires LDAR for equipment (e.g. valves, pumps, etc.) at least annually, and initial quarterly 

surveying of sources with projected annual throughput of crude oil and condensate combined that 

is greater than 25,000 barrels. The monitoring can be performed using Method 21 (leak definition 

of 500 ppm), a tunable diode laser absorption spectroscopy or an IR camera.50

Based on the above information, we determined that well sites in these states would already be 

subject to State leak requirements and would not be subject to the NSPS. According to our analysis, 21 

percent of the total number of new natural gas well completions, both conventional and fractured were 

covered by leak regulations in these four states. Therefore the number of new natural gas wells covered by 

federal regulations was estimated to be 6,691. Assuming 2 natural gas wells per well site, the number of 

new well sites in 2012 was estimated to be 3,346. An annual growth rate of 6.45 percent, which was 

determined from the NEMS data, was applied to the total number of new natural gas well completions, 

both conventional and hydraulically fractured in 2012, and used to estimate the total number of new 

natural gas completions, both conventional and hydraulically fractured in the years 2020 and 2025. The 

percentage of wells covered by State leak regulations, and the 2 natural gas wells per well site assumptions 

were applied to these totals to estimate the number of new natural gas production well sites. The projected 

number of new natural gas well sites was estimated to be 5,518 in 2020. Because the requirements have 

impacts annually, our projected activity for year 2025 was developed to reflect the impacts of the rule 

from 2020 through 2025, or 38,933 well sites in 2025. These estimated well site values were used to 

calculate the national fugitive emissions from natural gas well sites in 2012, 2020 and 2025. 

For oil wells, the same approach used for natural gas wells was used to estimate the number of new 

oil wells in the U.S. The number of new oil well completions in 2012, both conventional and hydraulically 

fractured, was determined to be 35,404. It was assumed that 9 percent of these oil wells are covered by 

State regulations in 2012 based on information in the HPDI database, which includes: Colorado, Ohio, 

Wyoming and Utah. Therefore 32,284 new oil wells were not covered by state leak regulations in 2012. 

Assuming 2 oil production wells per well site, the number of new oil production well sites was determined 

to be 16,142 in 2012. An annual growth rate of 0.32 percent, which was determined from the NEMS data, 

was applied to the total number of new oil well completions, both conventional and hydraulically fractured 

in 2012, and used to estimate the number of new oil well sites in the years 2020 and 2025. The percentage 

of wells covered by State leak regulations, and the 2 oil wells per well site assumptions were applied to 

                                                            

50 Utah regulations are available at http://www.deq.utah.gov/Permits/GAOs/docs/2014/6June/DAQE-AN149250001-14.pdf. 
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these totals to estimate the number of new oil well production sites. The projected number of new oil well 

sites was estimated to be 16,562 in 2020. Because the requirements have impacts annually, our projected 

activity for year 2025 was developed to reflect the impacts of the rule from 2020 through 2025, or 100,175 

well sites in 2025. This approach was used to support the regulatory impacts assessment process to reflect 

rule impacts from the effective date through 2025. These estimated well site values were used to calculate 

the nationwide fugitive emissions from oil production well sites in 2012, 2020 and 2025. 

5.3.2.2 Gathering and Boosting Stations 

The number of new gathering and boosting stations was estimated using the current number of 

gathering compressors estimated in the GHG Inventory. The total number of small and large gathering 

compressors was listed as 36,066 in the inventory. The GRI/EPA document does not include a separate list 

of compressor counts for gathering and boosting stations, but it does list the average number of 

compressors in the gas production section. It was assumed that this average of 4.5 compressors for gas 

production facilities is applicable to gathering and boosting stations. Therefore, using the total number of 

compressors in the GHG Inventory, the number of gathering and boosting stations was estimated to be 

8,015. To estimate the number of new gathering and boosting stations, we used an annual growth rate of 3 

percent, which is based on the gas well CAGR for new gas wells divided by the average wells per well 

site. This provided an estimate of 259 new gathering and boosting stations each year that would be 

affected sources under the proposed NSPS in each of the years 2012 and 2020. Because the requirements 

have impacts annually, our projected activity for year 2025 was developed to reflect the impacts of the rule 

from 2020 through 2025. This approach was used to support the regulatory impacts assessment process to 

reflect rule impacts from the effective date through 2025. 

5.3.2.3 Transmission and Storage Facilities 

The number of new transmission and storage facilities was estimated by reviewing the annual 

number of facilities from the year 1990 to 2012 estimated in the GHG Inventory and determining the rate 

of change in the number of these facilities over this period. For all the years, the annual number of new 

transmission stations was determined to be 24 and the annual change in storage facilities was determined 

to be 16. The average change for the last 10 years was also reviewed and the annual number of new 

transmission stations was determined to be 6 and the annual number of storage facilities was determined to 

be 15. Because of the fluctuation (both positive and negative) in the number of new transmission and 

storage stations from the years 1990 to 2012, it is assumed that the 10-year average change represents a 

better estimate of the current growth of the transmission and storage segment, therefore it will be assumed 

that there will 6 new transmission stations and 15 new storage stations each year that would be affected 
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sources under the proposed NSPS in each of the years 2012 and 2020. Because the requirements have 

impacts annually, our projected activity for year 2025 was developed to reflect the impacts of the rule 

from 2020 through 2025. This approach was used to support the regulatory impacts assessment process to 

reflect rule impacts from the effective date through 2025. 

5.3.3 Emission Estimates 

The nationwide emissions were calculated using the model plant data and the estimated number of 

new sources for each of the segments. The nationwide emission estimates for the total number of oil and 

natural gas production well sites, gathering and boosting stations, and transmission and storage facilities 

incrementally affected by the fugitive emission requirements in the NSPS for are summarized in Table 5-

12. The summary includes baseline emissions for each of these segments for projected years 2020 and 

2025. 

Table 5-12. Nationwide Baseline Emissions for Sources Subject to NSPS Monitoring and Repair 

Plans in 2020 and 2025 

Oil and Gas Segment Number of Sources 

Subject to NSPS 

CH4 Emissions 

(tpy) 

VOC Emissions 

(tpy) 

Base Year 2012 

Natural Gas Well Sites 3,346 15,188 4,222 

Oil Well Sites 16,142 17,555 4,880 

Gathering & Boosting Stations 259 9,102 2,530 

Transmission Stations 6 374 10.4 

Storage Stations 15 2,466 68 

Projected Year 2020 

Natural Gas Well Sites 5,518 25,048 6,963 

Oil Well Sites 16,562 18,011 5,007 

Gathering & Boosting Stations 259 9,102 2,530 

Transmission Stations 6 374 10.4 

Storage Stations 15 2,466 68 

Projected Year 2025 

Natural Gas Well Sites 38,933 176,726 49,125 

Oil Well Sites 100,175 108,942 30,283 

Gathering & Boosting Stations 1,554 54,612 15,181 

Transmission Stations 36 2245 62.1 

Storage Stations 90 14,798 410 
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5.4 Control Techniques 

5.4.1 Potential Control Techniques 

The EPA has determined that fugitive emissions from fugitive emissions components, such as 

valves, OELs, PRVs, thief hatches, pumps, and connectors, are a significant source of CH4, VOC and HAP 

emissions from oil and natural gas facilities. Previously, during development of the NSPS, the cost of 

using EPA Method 21 for leak detection combined with leak correction program was evaluated for the oil 

and natural gas source category and it was determined that the cost of control for use of this method was 

not reasonable for the production, gathering and boosting, and transmission and storage segments. 

However, we noted that we would continue to review available data and information to determine if these 

sources should be addressed in future rulemaking. 

Many of the fugitive emission measurements presented in the equipment leaks white paper were 

conducted with EPA Method 21 instruments (e.g., OVA, flame ionization detector, flow measurement 

devices). 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 and HAP compounds. These studies provided emission estimates in the form of 

component or equipment emission factors or emission estimates by facility. Even though there is a wide 

variation in the potential CH4 and VOC emissions, the studies showed that there are economic options for 

reducing these emissions. 

The detection of fugitive emissions from these sources can be determined using several 

technologies. Historically, fugitive emissions were detected using EPA Method 21 portable analyzers to 

determine if a leak exceeded a set threshold (e.g., the leak concentration was greater than the leak 

definition for the component). As described in the white paper, we believe that many fugitive emission 

surveys are now conducted using OGI which is a technology that operates much like a consumer videocamcorder and provides a real-time visual image of hydrocarbon gas emissions or leaks to the atmosphere. 

The OGI camera works by using spectral wavelength filtering and an array of IR detectors to visualize the 

IR absorption of hydrocarbons and other gaseous compounds. As the gas absorbs radiant energy at the 

same waveband that the filter transmits to the detector, the gas and motion of the gas is imaged. The OGI 

instrument can be used for monitoring a large array of equipment and components at a facility, and is an 

effective means of detecting fugitive emissions when the technology is used appropriately. Several studies 

in the white paper estimated that OGI can monitor 1,875-2,100 components per hour. In comparison, the 

average screening rate using a hand-held toxic vapor analyzers (TVA) or OVA is roughly 700 components 
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per day. However, the EPA’s recent work with OGI systems suggests these studies underestimate the 

amount of time necessary to thoroughly monitor components for fugitive emissions using OGI technology. 

Even though the amount of time may be underestimated, it is believed that the OGI system can reduce the 

cost of identifying fugitive emissions at oil and natural gas facilities when compared to using a handheld 

TVA or OVA. Another study in the white paper analyzed 4,293 leak detection surveys completed for the 

oil and gas industry using OGI systems and found the average abatement cost to be approximately $0 per 

ton of VOC and approximately -$375 per ton of VOC for well sites and compressor stations respectively. 

These estimates assume all leaks that are found are repaired and the recovered CH4 can be sold for 

$4/Mcf. 

Based on the review of the public and peer review comments on the white paper and the Colorado 

and Wyoming state rules, two options for reducing CH4 and VOC emissions from fugitive emissions 

components were identified: a fugitive emissions monitoring program based on the use of OGI combined 

with repair of the components that are found to have fugitive emissions and a fugitive emissions 

monitoring program based on individual component monitoring using EPA Method 21 for the detection of 

fugitive emissions combined repair of the components that are found to have fugitive emissions. Several 

public and peer reviewer comments on the white paper noted that these technologies are currently used by 

industry to reduce fugitive emissions from the production segment in the oil and natural gas industry. The 

costs and potential emissions reductions for both of these options depends on the frequency of the 

monitoring and the required repair threshold. For our analysis of the EPA Method 21 option, we can 

evaluate three leak repair thresholds: 500 ppm, 2,500 ppm and 10,000 ppm. For the OGI monitoring 

analysis, we conclude that any visible emissions that are imaged by the OGI instrument is a fugitive 

emission. Proper operation of the OGI instrument is critical for finding fugitive emissions; therefore, 

several operating procedures, such as daily verification check, determination of the maximum viewing 

distance from the components, and determination of the maximum wind speed during which monitoring 

can take place, are required. For all options we evaluated quarterly, semiannual and annual monitoring 

frequency. The following sections describe our evaluation to determine the potential emission reductions 

and the cost of control for these options. 

5.4.2 Fugitive Emissions Detection and Correction with OGI 

5.4.2.1 Description 

The reduction of fugitive emissions from well sites and compressor stations (i.e., gathering and 

boosting stations, transmission stations, and storage facilities) involves the development of a fugitive 
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emissions monitoring plan. Under this option, the monitoring is conducted using OGI. The company may 

use a corporate-wide monitoring plan that covers the collection of fugitive emissions components at well 

sites or compressor stations corporate-wide in conjunction with a plan that is site-specific to each 

collection of fugitive emissions components at well sites and compressor stations. As an alternative, an 

operator may develop a site-specific plan for each collection of fugitive emissions components that 

contains the requirements of the corporate-wide and site specific plans. The monitoring plan would 

include inspection of the collection of all fugitive emissions components, such as connectors, open-ended 

lines/valves, pressure relief devices, closed vent systems, compressors, and thief hatches and any other 

component known to have potential to have fugitive emissions. The plan must also include provisions to 

repair or replace fugitive emissions components if evidence of fugitive emissions is discovered during the 

OGI survey (e.g., any visible emissions from a fugitive emissions component observed using OGI). The 

OGI instrument that is used to conduct monitoring surveys must be capable of imaging gas that is half 

methane and half propane at a concentration of 10,000 ppm at a flow rate of ≥60 g/hr from a quarter inch 

diameter orifice. These criteria are based on the EPA’s recent work with OGI systems indicating that 

fugitive emissions at a concentration of at least 10,000 ppm are generally detectible using OGI with proper 

monitoring and operating practices. In order to estimate the cost of implementation of a monitoring and 

repair plan, we need to estimate the cost of repair, which is based on the number of components found to 

have fugitive emissions. Although with OGI the operator would not be able to determine the exact 

concentration of the fugitive emissions, all identified fugitive emissions would be required to be repaired. 

Because the repair threshold impacts the number of components repaired, and therefore, the cost of 

implementing the plan, for the purposes of our analysis, repair means that no visible emissions are 

observed when the fugitive emissions component is resurveyed using OGI. . The options to reduce 

emissions would then vary based on the frequency of the monitoring/repair of the components. If a 

fugitive emissions component cannot be immediately repaired during the monitoring survey, the operator 

must repair the component within 15 days of finding fugitive emissions. For this resurvey, the operator 

may use either OGI or Method 21 to confirm that the component is no longer emitted fugitive emissions. 

When OGI is used for the resurvey, no visible emissions indicate that the fugitive emissions component 

has been repaired. When Method 21 is used for the resurvey, no detectable emissions (e.g., a concentration 

of less than 500 ppm above background) indicate that the fugitive emissions component has been repaired. 

5.4.2.2 Emission Reduction Potential 

Information in the white paper related to the potential emission reductions from OGI monitoring 

and repair varied from 40 to 99 percent. The data from these studies are based on the gathering of 
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individual OGI surveys at various oil and natural gas 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 Commission51 which estimated 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 or equal to 

12 tpy (≥ 6 to ≤ 12 tpy), 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 (> 12 

to ≤ 50 tpy), and 80 percent reduction for monthly OGI monitoring at well production tank batteries with 

an uncontrolled VOC emission greater than 50 tpy (> 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 emissions 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 CH4 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. Table 5-13 summarizes the estimated nationwide baseline emission reductions from a 

monitoring and repair program using an OGI monitoring and repair plan for the various segments. See 

tables A-33 through A-60 in Appendix A for detailed calculations of emissions, reductions, cost of control 

and nationwide impacts. 

                                                            

51 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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Table 5-13. Nationwide Emission Reductions for OGI Monitoring and Repair Plan Options for 2020 

and 2025 

Oil and Gas 

Segment 

Number of 

New 

Facilities 

Annual Monitoring 

(tpy)a

Semiannual 

Monitoring 

(tpy)a

Quarterly Monitoring 

(tpy)a

CH4 VOC CH4 VOC CH4 VOC 

Base Year 2012 

Natural Gas Well 

Sites 3,346 6,075 1,689 9,101 2,533 12,151 3,378 

Oil Well Sites 16,142 7,022 1,952 10,492 2,922 14,044 3,904 

Gathering & 

Boosting Stations 259 3,641 1,012 5,461 1,518 7,282 2,024 

Transmission 

Stations 6 150 4 225 6 299 8 

Storage Stations 15 987 27 1,480 41 1,973 55 

Projected Year 2020 

Natural Gas Well 

Sites 5,518 10,019 2,785 15,029 4,178 20,038 5,570 

Oil Well Sites 16,562 7,205 2,003 10,807 3,004 14,409 4,005 

Gathering & 

Boosting Stations 259 3,641 1,012 5,461 1,518 7,282 2,024 

Transmission 

Stations 6 150 4 225 6 299 8 

Storage Stations 15 987 27 1,480 41 1,973 55 

Projected Year 2025 

Natural Gas Well 

Sites 38,933 69,710 19,378 106,036 29,475 139,420 38,755 

Oil Well Sites 100,175 43,577 12,113 65,365 18,170 87,153 24,226 

Gathering & 

Boosting Stations 1,554 21,845 6,072 32,767 9,108 43,689 12,144 

Transmission 

Stations 36 898 25 1,347 37 1,796 50 

Storage Stations 90 5,919 164 8,879 246 11,838 328 

a. Assumes 40% reduction with the implementation of annual IR camera monitoring, 60% reduction with the implementation 

of semi-annual IR camera monitoring and 80% with the implementation of quarterly IR camera monitoring. 

5.4.2.3 Cost Impacts 

Costs for preparing an OGI fugitive emission monitoring and repair plan on a company level were 

estimated using hourly estimates for each of the plan elements. The costs are based on the following 

assumptions: 

 Labor cost for each of the monitoring plan elements, such as reading the rule, was estimated to be 

$57.80 per hour. 

 Reading of the rule and instructions would take 1 person 4 hours to complete at a cost of $231.20 
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 Development of a fugitive emission monitoring plan would take 2.5 people a total of 60 hours to 

complete at a cost of $3,468. 

 Initial activities planning are estimated to take 2 people a total of 32 hours to complete at a cost of 

$1,849. 

 Notification of compliance status was estimated to take 1 person 1 hour to complete at a cost of 

$58 for gathering and boosting stations, transmission stations, and storage facilities. For companies 

that own and operate production well sites, the cost notification of compliance status was estimated 

to be $58 per well site for a company that owns 22 well sites for a total of $1,272 per company. 

 Cost of a Method 21 Monitoring Device of $10,800. 

 Subsequent activities planning are estimated to take 2 people a total of 12 hours to complete at a 

cost of $1,387. For oil and natural gas production 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 were estimated for 

each of the monitoring and repair elements. The costs are based on the following assumptions: 

 The cost for OGI monitoring using an outside contractor was assumed to be $600 for a well 

production site and $2,300 for a gathering and boosting station, a transmission station and a storage 

facility.52 

 Annual repair costs were estimated to be $597 for production well sites, $6,871 for gathering and 

boosting stations, $6,721 for transmission stations, and $13,892 for storage facilities. These costs 

were estimated assuming that 1.18% of the components leak53 and 75% are repaired online and 

25% are repaired offline. 

 Cost to resurvey the repaired components using a Method 21 device that could not be fixed during 

the initial survey based on $2.00 per component. This is based on the assumption that a company 

                                                            

52 Costs for contractor based OGI monitoring obtained from the Carbon Limits report. 53 The assumption of 1.18% leak rate for OGI monitoring was obtained from Table 5 of the Uniform Standards memorandum. 

The 1.18% value is the baseline leak frequency for valves in gas/vapor service. None of the other baseline frequencies in this 

table were used because the equipment are in liquid service (e.g., pumps LL, valve LL, agitators LL). There is no information 

on the number of leaks located at uncontrolled facilities, only average percentages of the total number of components at a 

facility. Therefore, our methodology was to use the 1.18% leak frequency value from the Uniform Standards memorandum and 

apply that value to the total number of components at the oil and natural gas model plant. (Uniform Standards 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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purchases Method 21 instrumentation (estimated to be $10,80054) and is able to perform the 

resurvey without retaining contractors. 

 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 cost for oil and natural gas production well sites was calculated by 

summing up the costs for reading the rule, development of fugitive emissions monitoring plan, initial 

activities planning, notification of initial compliance status, and purchase of a Method 21 instrumentation. 

The total capital cost of these activities was calculated to be $17,620 per company. Assuming that each 

company owns and operates 22 well sites55, the capital cost per well site was estimated to be $801. For 

gathering and boosting, transmission and storage compressor stations the capital cost for reading the rule, 

development of fugitive emissions monitoring plan, initial activities planning notification of initial 

compliance status, and purchase of a Method 21 instrumentation was calculated to be $16,407 per facility. 

For all oil and natural gas segments, the annual cost includes; subsequent activities planning, OGI 

survey, cost of repair of fugitive emissions found, resurvey of repaired components, preparation and 

submittal of an annual report, and the amortized capital cost over 8 years at 7 percent interest. For our 

analysis we calculated the annual cost for annual, semiannual and quarterly OGI surveys. Tables 5-14, 5-

15 and 5-16 summarizes the annual cost for each segment at each of the three survey frequencies. Tables 

A-7 through A-10 in Appendix A present the analysis for the estimated annual cost of implementing an 

OGI monitoring and repair program for oil and natural gas production well sites, gathering and boosting, 

transmission and storage compressor stations for the respective OGI monitoring frequencies. 

The cost per ton of emissions reduced was calculated using two separate methods. The first method 

allocated all of the costs to each pollutant separately (single-pollutant approach) using representative unit 

costs for each control option. The second method allocates the annual cost among the pollutants (multipollutant approach) that a given technology reduced (i.e., CH4 and VOC). This proration was based on 

estimates of the percentage reduction expected for each pollutant. In the case of fugitives, the percent 

reductions for CH4 and VOC are equal; and therefore the proration of the annual cost was divided equally 

and applied to the CH4 and VOC reductions. 

                                                            

54 Average of subsequent monitoring costs in Table 13 from the Memorandum to Jodi Howard, EPA/OAQPS from Cindy 

Hancy, RTI International, Analysis of Emission Reduction Techniques for Equipment Leaks, December 21, 2011. EPA-HQOAR-2002-0037-0180

55 The number of well sites owned and operated by companies was calculated using data from the Fort Worth study.
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Based on estimated emissions reductions and the estimated cost for implementing an OGI fugitive 

emissions monitoring and repair program at the affected facilities, we calculated a cost of control for CH4

and VOC for the various options for oil and natural gas production well sites, gathering and boosting, 

transmission and storage compressor stations. We then calculated the cost of control of well sites and 

compressor stations using the weighted average cost of control all well sites and all compressor stations 

(i.e., gathering and boosting, transmission and storage). Table 5-14, 5-15 and 5-16 presents a summary of 

the cost of control for CH4 and VOC for the three OGI monitoring frequency options (i.e., annual, 

semiannual and quarterly, respectively) based on the single-pollutant method of 100 percent of the cost 

being attributed to the individual pollutants. Tables 5-17, 5-18 and 5-19 present a summary of the capital 

and annual costs, and the cost of control for CH4 and VOC using the multi-pollutant method (i.e., 50 

percent of the cost attributed to methane and 50 percent of the cost attributed to VOC). See Tables A-33 

through A-60 in Appendix A for detail on the emissions, reductions and cost of control calculations for the 

various options for each segment. 

5.4.2.4 Secondary Impacts 

No secondary gaseous pollutant emissions or wastewater are generated during the monitoring and 

repair of fugitive emissions components. There are some emissions that would be generated by the IR 

camera monitoring contractors with respect to driving to and from the site for the fugitive emissions 

survey however, these emissions cannot be quantified because there is no data related to the distance that 

would need to be traveled to the site. However, it is believed that the secondary impacts expected from the 

implementation of an OGI monitoring program would be minimal.
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Table 5-14. Summary of the Model Plant Cost of Control for the Annual OGI Monitoring O

Single-Pollutant 

Model Plant 

Annual Emission 

Reductionsa

(tpy) Capital Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

Natural Gas Production Well Sited 1.82 0.50 $801 $1,329 $908 $732 $2,633 Oil Production Well Sited 0.44 0.12 $801 $1,329 $1,228 $3,055 $10,992 

Well Site Program Weighted Averageh $2,475 $8,903 

Gathering & Boosting Statione 14.1 3.9 $16,407 $10,124 $6,865 $720 $2,591 Transmission Stationf 24.9 0.7 $16,407 $10,049 $4,882 $403 $14,554 Storage Facilityg 65.8 1.8 $16,407 $13,634 $15 $207 $7,491 

Compressor Stations Program Weighted Averageh $686 $3,110 

a. Assumes 40% reduction with the implementation of annual IR camera monitoring. b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $17,620 divideaverage of 22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost o

monitoring program of $16,407. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas re

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $1,195 and amortization of the capital cost over 8 years at 7% inte. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $7,376 and amortization of the capital cost interest. f. Annual cost for transmission station includes annual monitoring and repair cost of $7,301 and amortization of the capital cost over 8 yearg. Annual cost for storage facilities includes annual monitoring and repair cost of $10,866and amortization of the capital cost over 8 years ah. The weighted average for the segments were calculated using the 2020 activity counts of 5518 gas well sites, 16562 oil well sites, 259 G&

transmission stations and 15 storage facilities. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the leaks was not estimated for the transmission and storage segment.
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Table 5-15. Summary of the Model Plant Cost of Control for the Semiannual OGI Monitoring Option 

Model Plant 

Annual Emission 

Reductionsa

(tpy) Capital Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

Natural Gas Production Well Sited 2.72 0.76 $801 $2,230 $1,599 $819 $2,945 Oil Production Well Sited 0.65 0.18 $801 $2,230 $2,079 $3,417 $12,294 

Well Site Program Weighted Averageh $2,768 $9,958 

Gathering & Boosting Statione 21.1 5.9 $16,407 $15,881 $10,993 $753 $2,710 Transmission Stationf 37.4 1.0 $16,407 $15,732 $7,982 $420 $15,190 Storage Facilityg 98.7 2.7 $16,407 $22,902 $2,473 $232 $8,388 

Compressor Stations Program Weighted Averageh $718 $3,281 

a. Assumes 60% reduction with the implementation of semiannual IR camera monitoring. b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $17,620 divideaverage of 22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost o

monitoring program of $16,407. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas re

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $2,096 and amortization of the capital cost over 8 years at 7% inte. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $13 133 and amortization of the capital cosinterest. f. Annual cost for transmission station includes annual monitoring and repair cost of $12,984 and amortization of the capital cost over 8 yeag. Annual cost for storage facilities includes annual monitoring and repair cost of $20,154 and amortization of the capital cost over 8 years ah. The weighted average for the segments were calculated using the 2020 activity counts of 5518 gas well sites, 16562 oil well sites, 259 G&

transmission stations and 15 storage facilities. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the leaks was not estimated for the transmission and storage segment.
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Table 5-16. Summary of the Model Plant Cost of Control for the Quarterly OGI Monitoring Option -

Model Plant 

Annual Emission 

Reductionsa

(tpy) Capital Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

Natural Gas Production Well Sited 3.63 1.01 $801 $4,031 $3,190 $1,110 $3,994 Oil Production Well Sited 0.87 0.24 $801 $4,031 $3,830 $4,634 $16,669 

Well Site Program Weighted Averageh $3,753 $13,502 

Gathering & Boosting Statione 28.1 7.8 $16,407 $27,396 $20,879 $974 $3,506 Transmission Stationf 49.9 1.4 $16,407 $27,097 $16,765 $543 $19,623 Storage Facilityg 131.5 3.6 $16,407 $41,437 $14,199 $315 $11,383 

Compressor Stations Program Weighted Averageh $930 $4,273 

a. Assumes 80% reduction with the implementation of quarterly IR camera monitoring. b The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $17,620 divided 

of 22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost of implemmonitoring program of $16,407. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas re

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $3,897 and amortization of the capital cost over 8 years at 7% inte. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $24,649 and amortization of the capital cosinterest. f. Annual cost for transmission station includes annual monitoring and repair cost of $24,350 and amortization of the capital cost over 8 yeag. Annual cost for storage facilities includes annual monitoring and repair cost of $38,689 and amortization of the capital cost over 8 years ah. The weighted average for the segments were calculated using the 2020 activity counts of 5518 gas well sites, 16562 oil well sites, 259 G&

transmission stations and 15 storage facilities. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the leaks was not estimated for the transmission and storage segment.
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Table 5-17. Summary of the Model Plant Cost of Control for the Annual OGI Monitoring Option - Mult

Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

Natural Gas Production Well Sited 1.82 0.50 $801 $1,329 $908 $366 $1,317 Oil Production Well Sited 0.44 0.12 $801 $1,329 $1,228 $1,528 $5,496 $

Well Site Program Weighted Averageh $1,237 $4,451 $

Gathering & Boosting Statione 14.1 3.9 $16,407 $10,124 $6,865 $360 $1,295 Transmission Stationf 24.9 0.7 $16,407 $10,049 $4,882 $201 $7,277 Storage Facilityg 65.8 1.8 $16,407 $13,634 $15 $104 $3,745 

Compressor Stations Program Weighted Averageh $343 $1,555 

a. Assumes 40% reduction with the implementation of annual IR camera monitoring. b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $17,620 divideaverage of 22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost o

monitoring program of $16,407. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas re

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $1,195 and amortization of the capital cost over 8 years at 7% inte. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $7,376 and amortization of the capital cost interest. f. Annual cost for transmission station includes annual monitoring and repair cost of $7,301 and amortization of the capital cost over 8 yearg. Annual cost for storage facilities includes annual monitoring and repair cost of $10,866and amortization of the capital cost over 8 years ah. The weighted average for the segments were calculated using the 2020 activity counts of 5518 gas well sites, 16562 oil well sites, 259 G&

transmission stations and 15 storage facilities. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the leaks was not estimated for the transmission and storage segment.
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Table 5-18. Summary of the Model Plant Cost of Control for the Semiannual OGI Monitoring Option - Mu

Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

Natural Gas Production Well Sited 2.72 0.76 $801 $2,230 $1,599 $409 $1,473 Oil Production Well Sited 0.65 0.18 $801 $2,230 $2,079 $1,709 $6,147 $

Well Site Program Weighted Averageh $1,384 $4,979 $

Gathering & Boosting Statione 21.1 5.9 $16,407 $15,881 $10,993 $377 $1,355 Transmission Stationf 37.4 1.0 $16,407 $15,732 $7,982 $210 $7,595 Storage Facilityg 98.7 2.7 $16,407 $22,902 $2,473 $116 $4,194 

Compressor Stations Program Weighted Averageh $359 $1,641 

a. Assumes 60% reduction with the implementation of semiannual IR camera monitoring. b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $17,620 divideaverage of 22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost o

monitoring program of $16,407. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas re

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $2,096 and amortization of the capital cost over 8 years at 7% inte. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $13 133 and amortization of the capital cosinterest. f. Annual cost for transmission station includes annual monitoring and repair cost of $12,984 and amortization of the capital cost over 8 yeag. Annual cost for storage facilities includes annual monitoring and repair cost of $20,154 and amortization of the capital cost over 8 years ah. The weighted average for the segments were calculated using the 2020 activity counts of 5518 gas well sites, 16,562 oil well sites, 259 G

transmission stations and 15 storage facilities. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the leaks was not estimated for the transmission and storage segment.
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Table 5-19. Summary of the Model Plant Cost of Control for the Quarterly OGI Monitoring Option - Mu

Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

C

(

CH4 VOC without savings with savings CH4 VOC CH

Natural Gas Production Well Sited 3.63 1.01 $801 $4,031 $3,190 $555 $1,997 $4Oil Production Well Sited 0.87 0.24 $801 $4,031 $3,830 $2,317 $8,335 $2,2

Well Site Program Weighted Averageh $1,877 $6,751 $1,7

Gathering & Boosting Statione 28.1 7.8 $16,407 $27,396 $20,879 $487 $1,753 $3Transmission Stationf 49.9 1.4 $16,407 $27,097 $16,765 $272 $9,812 $2Storage Facilityg 131.5 3.6 $16,407 $41,437 $14,199 $158 $5,692 $1

Compressor Stations Program Weighted Averageh $465 $2,136 $3

a. Assumes 80% reduction with the implementation of quarterly IR camera monitoring. b The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $17,620 divided 

of 22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost of implemmonitoring program of $16,407. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas re

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $3,897 and amortization of the capital cost over 8 years at 7% inte. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $24,649 and amortization of the capital cosinterest. f. Annual cost for transmission station includes annual monitoring and repair cost of $24,350 and amortization of the capital cost over 8 yeag. Annual cost for storage facilities includes annual monitoring and repair cost of $38,689 and amortization of the capital cost over 8 years ah. The weighted average for the segments were calculated using the 2020 activity counts of 5518 gas well sites, 16562 oil well sites, 259 G&

transmission stations and 15 storage facilities. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the leaks was not estimated for the transmission and storage segment. 
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5.4.3 Fugitive Emissions Detection and Correction with EPA Method 21 

5.4.3.1 Description 

Although we are not proposing to specifically allow the use of Method 21 to detect fugitive 

emissions from the collection of the fugitive emissions components at well sites and compressor stations, 

we have evaluated Method 21 as an option to allow comment on whether Method 21 should be allowed for 

fugitive emissions monitoring in the final rule. Under this option, the reduction of fugitive emissions from 

well sites, gathering and compressor stations (i.e., boosting stations, transmission and storage facilities) 

also involves the development of a fugitive emissions monitoring plan, except that the monitoring is 

conducted using EPA Method 21 instead of OGI, as described above. The Method 21 monitoring includes 

the development of fugitive emissions monitoring plan, surveying using Method 21 instrumentation, resurvey of repaired components and the preparation and submittal of an annual report. The company may 

use the same monitoring plan for all affected sources, a different plan for each category of a source, or a 

plan for each individual source. The monitoring plan must include inspection of the collection of fugitive 

emissions components, such as connectors, open-ended lines/valves, pressure relief devices, closed vent 

systems, compressors, and thief hatches. The plan must also include provisions to repair or replace fugitive 

emissions components as soon as practicable if evidence of fugitive emissions is discovered during the 

Method 21 survey but no later than 15 days of such a discovery. In addition, all repairs must be resurveyed immediately after repair using OGI or Method 21 to ensure the fugitive emissions are no longer 

visible or is below a leak repair threshold of the plan. For our analysis, we evaluated three potential repair 

thresholds for Method 21 plans; 500 ppm, 2,500 ppm and 10,000 ppm. Therefore, options to reduce 

emissions under this option would vary based on the frequency of the monitoring/repair of the components 

as well as the repair threshold of the plan. 

5.4.3.2 Emission Reduction Potential 

In our analysis, we estimated emissions reductions for annual, semiannual and quarterly options for 

conducting the Method 21 monitoring at the three repair threshold levels of 500 ppm, 2,500 ppm and 

10,000 ppm. The EPA Equipment Leaks Protocol document provides emissions factor data based on leak 

definition and monitoring frequencies primarily for the Synthetic Organic Chemical Manufacturing 

Industry (SOCMI) and Petroleum Refining Industry. This data was used to estimate the uncontrolled 

emissions (i.e., baseline emissions0 and the corresponding emission reduction percentages that could 

potentially be achieved for each of the leak definitions (500 ppm, 2,500 ppm, 10,000 ppm) and monitoring 

frequencies (annual, semiannual, quarterly). Using this information we calculated an expected emissions 
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reduction percentage for each of the combinations of monitoring frequency and repair threshold. Table 5-

20 summarizes calculated percent of expected reduction for each of the combinations. 

Table 5-20. Percent Reduction in Emissions for EPA Method 21 Monitoring and Repair Plan 

Options 

Monitoring Frequency Repair Threshold 

10,000 ppm 2,500 ppm 500 ppm 

Annual 82 94 98 

Semiannual 72 92 97 

Quarterly 67 89 94 

Based on these reduction percentages we calculated the estimated nationwide baseline emissions 

for the various options for a Method 21 monitoring and repair plan. Table 5-21 summarizes the estimated 

nationwide baseline emission reductions Method 21 monitoring repair plans. 

Table 5-21. Nationwide Emission Reductions for EPA Method 21 Monitoring and Repair Plan 

Options for 2020 and 2025 

Oil and Gas 

Segment 

Number of 

New 

Facilities 

Annual Monitoring 

(tpy)a 

Semiannual 

Monitoring 

(tpy)a

Quarterly 

Monitoring 

(tpy)a

CH4 VOC CH4 VOC CH4 VOC 

Base Year 2012 

10,000 ppm 

Natural Gas Well 

Sites 3,346 33,872 9,415 29,741 8,267 27,676 7,693 

Oil Well Sites 16,142 15,154 4,212 18,503 5,143 17,218 4,786 

Gathering & 

Boosting Stations 259 7,464 2,075 6,553 1,822 6,098 1,695 

Transmission 

Stations 6 307 8 269 7 251 7 

Storage Stations 15 2,022 56 1,776 49 1,652 46

2,500 ppm 

Natural Gas Well 

Sites 3,346 38,828 2,856 38,002 2,795 36,763 2,704 

Oil Well Sites 16,142 17,371 426 17,002 417 16,447 403 

Gathering & 

Boosting Stations 259 8,556 2,378 8,374 2,328 8,101 2,252 

Transmission 

Stations 6 352 10 344 10 333 9 

Storage Stations 15 2,318 64 2,269 63 2,195 61
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Oil and Gas 

Segment 

Number of 

New 

Facilities 

Annual Monitoring 

(tpy)a 

Semiannual 

Monitoring 

(tpy)a

Quarterly 

Monitoring 

(tpy)a

CH4 VOC CH4 VOC CH4 VOC 

500 ppm 

Natural Gas Well 

Sites 3,346 40,481 2,977 40,068 2,947 38,828 2,856 

Oil Well Sites 16,142 18,110 444 17,926 439 17,371 426 

Gathering & 

Boosting Stations 259 8,920 2,480 8,829 2,454 8,556 2,378 

Transmission 

Stations 6 367 10 363 10 352 10 

Storage Stations 15 2,417 67 2,392 66 2,318 64

Projected Year 2020 

10,000 ppm 

Natural Gas Well 

Sites 5,518 20,539 5,709 18,034 5,013 16,782 4,665 

Oil Well Sites 16,562 14,769 4,106 12,968 3,605 12,068 3,354 

Gathering & 

Boosting Stations 259 7,464 2,075 6,553 1,822 6,098 1,695 

Transmission 

Stations 6 307 8 269 7 251 7 

Storage Stations 15 2,022 56 1,776 49 1,652 46 

2,500 ppm 

Natural Gas Well 

Sites 5,518 23,545 6,565 23,044 6,406 22,292 6,197 

Oil Well Sites 16,562 16,931 4,706 16,570 4,606 16,030 4,456 

Gathering & 

Boosting Stations 259 8,556 2,378 8,374 2,328 8,101 2,252 

Transmission 

Stations 6 352 10 344 10 333 9 

Storage Stations 15 2,318 64 2,269 63 2,195 61 

500 ppm 

Natural Gas Well 

Sites 5,518 24,547 6,823 24,296 6,754 23,545 6,545 

Oil Well Sites 16,562 17,651 4,907 17,471 4,857 16,931 4,706 

Gathering & 

Boosting Stations 259 8,920 2,480 8,829 2,454 8,556 2,378 

Transmission 

Stations 6 367 10 363 10 352 10 

Storage Stations 15 2,417 67 2,392 66 2,318 64 
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Oil and Gas 

Segment 

Number of 

New 

Facilities 

Annual Monitoring 

(tpy)a 

Semiannual 

Monitoring 

(tpy)a

Quarterly 

Monitoring 

(tpy)a

CH4 VOC CH4 VOC CH4 VOC 

Projected Year 2025 

10,000 ppm 

Natural Gas Well 

Sites 38,933 144,916 40,283 127,243 35,370 118,407 32,914 

Oil Well Sites 100,175 89,332 24,832 78,438 21,804 72,991 20,290 

Gathering & 

Boosting Stations 1,554 44,781 12,448 39,320 10,930 36,590 10,171 

Transmission 

Stations 36 1,841 51 1,617 45 1,504 42 

Storage Stations 90 12,134 336 10,654 295 9,914 274 

2,500 ppm 

Natural Gas Well 

Sites 38,933 166,123 46,178 162,588 45,195 157,286 43,722 

Oil Well Sites 100,175 102,405 28,466 100,226 28,860 96,958 26,952 

Gathering & 

Boosting Stations 1,554 51,335 14,270 50,243 13,966 48,604 13,511 

Transmission 

Stations 36 2,111 58 2,066 57 1,998 55 

Storage Stations 90 13,910 385 13,614 377 13,170 364 

500 ppm 

Natural Gas Well 

Sites 38,933 173,192 48,143 171,424 47,652 166,123 46,178 

Oil Well Sites 100,175 106,763 29,677 105,673 29,375 102,405 28,466 

Gathering & 

Boosting Stations 1,554 53,519 14,877 52,973 14,725 51,335 14,270 

Transmission 

Stations 36 2,200 61 2,178 60 2,111 58 

Storage Stations 90 14,502 401 14,354 397 13,910 385 

a. Assumes percent reduction as shown in Table 5-17. 

5.4.2.3 Cost Impacts 

Costs 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: 

 Labor cost for each of the monitoring plan elements was estimated to be $57.80 per hour. 

 Reading of the rule and instructions would take 1 person 4 hours to complete at a cost of $231.20 

 Development of a fugitive emission monitoring plan would take 2.5 people a total of 60 hours to 

complete at a cost of $3,468. 
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 Initial activities planning are estimated to take 2 people a total of 16 hours to complete at a cost of 

$1,849. 

 Notification of compliance status was estimated to take 1 person 1 hour to complete at a cost of 

$58 for gathering and boosting stations, transmission stations, and storage facilities. For companies 

that own and operate production well sites, the cost for notification of compliance status was 

estimated to be $58 for 22 well sites for a total of $1,272 per company. 

 Cost for a Method 21 monitoring device ($10,800) and data collection system ($14,500).56

 Subsequent activities planning are estimated to take 2 people a total of 12 hours to complete at a 

cost of $1,387. For oil and natural gas production 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 were estimated for 

each of the monitoring and repair elements. The costs are based on the following assumptions: 

 The cost for Method 21 monitoring was estimated to be $462, assuming 2 people and 4 hours per 

person to survey a well production site using a M21 monitoring device, and $925, assuming 2 

people and 8 hours per person to survey a gathering and boosting, transmission, and storage facility 

using a M21 monitoring device. 

 Repair costs were estimated to be $2,999 at a leak definition of 10,000 ppm, $5,067 at a leak 

definition of 2,500 ppm and $5,400 at a leak definition of 500 ppm for production well sites. For 

compressor stations (i.e., gathering and boosting, transmission, storage), repair costs were 

estimated to be $29,288 at a leak definition of 10,000 ppm, $47,821 at a leak definition of 2,500 

ppm and $52,900 at a leak definition of 500 ppm. These costs are based on leak percentages of 

7.49 percent at a leak definition of 10,000 ppm, 12.25 percent at a leak definition of 2,500 ppm and 

13.53 percent at a leak definition of 500 ppm. The leak percentages were calculated using the 

baseline SOCMI emission rate (0.00597 kg/hr/source) and the average leak rate to fraction leaking 

equations for 500, 2,500 and 10,000 ppmv leak definition in Table 5-4 of the EPA Protocol for 

Equipment Leak Emission Estimates. No data was available that included monitoring frequency, 

therefore it was assumed that the leak percentage represented the total annual leaks found using 

Method 21. 

                                                            

56 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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 Cost for resurvey of components after repair based on $2.00 per component resurveyed. 

 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 cost for oil and natural gas production 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 cost of these activities 

was calculated to be $32,120 per company. Assuming that each company owns and operates 22 well sites, 

the capital cost per well site was estimated to be $1,460. For gathering and boosting, transmission, and 

storage facilities the capital cost for reading the rule, development of fugitive emissions monitoring plan, 

initial activities planning, and notification of initial compliance status was calculated to be $30,907 per 

facility. 

For all segments, the annual cost includes; subsequent activities planning, Method 21 survey, cost 

of repair of fugitive emissions found, resurvey of the repaired components, preparation and submittal of an 

annual report, and the amortized capital cost over 8 years at 7 percent interest. For our analysis we 

calculated the annual cost for annual, semiannual and quarterly Method 21 surveys using the three repair 

thresholds. Tables 5-22, 5-23 and 5-24 summarizes the capital and annual cost for each segment at each of 

the three survey frequencies and three repair thresholds. Tables A-1 through A-6 in Appendix A provide 

the detailed calculations of the annual cost for the Method 21 monitoring and repair program under the 

nine sub-option combinations of monitoring frequency and repair threshold. 

The cost per ton of emissions reduced was calculated using two separate methods. The first method 

attributes all of the costs to each pollutant separately (the single-pollutant method) using representative 

unit costs for each control option. The second method allocates the annual cost among the pollutants 

(multi-pollutant method) that a given technology reduced (i.e., CH4 and VOC). This proration was based 

on estimates of the percentage reduction expected for each pollutant. In the case of fugitives, the percent 

reductions for CH4 and VOC are equal; and therefore the allocation of the annual cost was divided equally 

and applied to the CH4 and VOC reductions. 

Based on estimated emissions reductions and the estimated cost for implementing a Method 21 

fugitive emissions monitoring and repair program at the affected facilities, we calculated a cost of control 

for CH4 and VOC for the various sub-options for oil and natural gas production well sites, gathering and 

boosting stations, transmission stations and storage facilities. We also calculated the weighted average cost 

of control for all well sites and all compressor stations under each of the monitoring and repair plan sub 
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options. Tables 5-22, 5-23 and 5-24 present a summary of capital and annual costs and the cost of control 

for CH4 and VOC for the Method 21 plan monitoring options (i.e., annual, semiannual and quarterly, 

respectively) and the three repair thresholds (i.e., 10,000 ppm, 2,500 ppm and 500 ppm, respectively) 

based on 100 percent of the cost being attributed to the individual pollutants. Tables 5-23, 5-24 and 5-25 

present a summary of the capital and annual costs, and the cost of control for CH4 and VOC using the 

multi-pollutant method (i.e., 50 percent of the cost attributed to methane and 50 percent of the cost 

attributed to VOC). See Tables A-11 through A-32 in Appendix A for detail on the calculations of 

emissions, reductions and the cost of control analysis for the various sub-options for each segment. 

5.4.2.4 Secondary Impacts 

No secondary gaseous pollutant emissions or wastewater are generated during the monitoring and 

repair of fugitive emissions from leaks. There are some emissions that would be generated by the Method 

21 monitoring with the exception of employee or contractors driving to and from the site for the fugitive 

emissions survey, however, these emissions cannot be quantified because there is no data related to the 

distance that would need to be traveled to the site. However, it is believed that the secondary impacts 

expected from the implementation of a Method 21 monitoring and repair program would be minimal.
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Table 5-22. Summary of the Model Plant Cost of Control for the Annual Method 21 Monitoring and Repa

Pollutant 

Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

10,000 ppm

Natural Gas Production Well Sited 3.72 1.03 $1,460 $4,020 $3,157 $1,080 $3,885 Oil Production Well Sited 0.73 0.20 $1,460 $4,020 $3,813 $5,517 $19,847 

Well Site Program Weighted Averageh $4,408 $15,858 

Gathering and Boosting Statione 28.8 8.01 $30,907 $37,203 $30,523 $1,291 $4,644 Transmission Statione 51.1 1.42 $30,907 $37,203 $37,203 $727 $26,284 Storage Facilitye 134.8 3.73 $30,907 $37,203 $37,203 $276 $9,971 

Compressor Station Weighted Average $1,225 $5,393 

2,500 ppm

Natural Gas Production Well Sited 4.27 1.19 $1,460 $6,103 $5,113 $1,430 $5,145 Oil Production Well Sited 1.02 0.28 $1,460 $6,103 $5,866 $5,970 $21,475 

Well Site Program Weighted Averageh $4,835 $17,394 

Gathering and Boosting Statione 33.0 9.18 $30,907 $55,860 $48,203 $1,691 $6,083 Transmission Statione 58.6 1.62 $30,907 $55,860 $55,860 $953 $34,427 Storage Facilitye 154.6 4.28 $30,907 $55,860 $55,860 $361 $13,060 

Compressor Station Weighted Average $1,604 $7,064 
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Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

500 ppm

Natural Gas Production Well Sited 4.45 1.24 $1,460 $6,437 $5,406 $1,447 $5,206 Oil Production Well Sited 1.07 0.30 $1,460 $6,437 $6,190 $6,040 $21,728 

Well Site Program Weighted Averageh $4,892 $17,599 

Gathering and Boosting Statione 34.4 9.57 $30,907 $60,973 $52,990 $1,770 $6,369 Transmission Statione 61.1 1.69 $30,907 $60,973 $60,973 $998 $36,045 Storage Facilitye 161.1 4.46 $30,907 $60,973 $60,973 $378 $13,673 

Compressor Station Weighted Average $1,679 $7,396 

a. Assumes 82% reduction with the implementation of repair threshold of 10,000 ppm, 94% reduction for 2,500 ppm and 98% for 500 ppm monitoring. b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divid22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost of implemprogram of $30,907. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas 

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $3,775 for 10,000 ppm repair threshold, $5,858 for 2,500 ppm and amortization of the capital cost over 8 years at 7% interest. e. Annual cost for compressor stations (i.e., gathering and boosting, transmission and storage) includes annual monitoring and repair cost repair threshold, $50,685 for 2,500 ppm and $55,973 for 500 ppm and amortization of the capital cost over 8 years at 7% interest. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as tleaks was not estimated for the transmission or storage segment. 
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Table 5-23. Summary of the Model Plant Cost of Control for the Semiannual Method 21 Monitoring and 

Single-Pollutant 

Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

10,000 ppm

Natural Gas Production Well Sited 3.27 0.91 $1,460 $4,482 $3,725 $1,371 $4,934 Oil Production Well Sited 0.78 0.22 $1,460 $4,482 $4,301 $5,724 $20,593 

Well Site Program Weighted Averageh $4,637 $16,680 

Gathering and Boosting Statione 25.3 7.03 $30,907 $38,128 $32,263 $1,507 $5,421 Transmission Statione 44.9 1.24 $30,907 $38,128 $38,128 $849 $30,679 Storage Facilitye 118.4 3.28 $30,907 $38,128 $38,128 $322 $11,638 

Compressor Station Weighted Average $1,429 $6,295 

2,500 ppm

Natural Gas Production Well Sited 4.18 1.16 $1,460 $6,565 $5,597 $1,572 $5,655 Oil Production Well Sited 1.00 0.28 $1,460 $6,565 $6,333 $6,562 $23,605 

Well Site Program Weighted Averageh $5,315 $19,119 

Gathering and Boosting Statione 32.3 8.99 $30,907 $56,785 $49,291 $1,756 $6,318 Transmission Statione 57.4 1.59 $30,907 $56,785 $56,785 $990 $35,758 Storage Facilitye 151.3 4.19 $30,907 $56,785 $56,785 $375 $13,565 

Compressor Station Weighted Average $1,666 $7,337 

500 ppm
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Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

Natural Gas Production Well Sited 4.40 1.22 $1,460 $6,899 $5,879 $1,567 $5,637 Oil Production Well Sited 1.05 0.29 $1,460 $6,899 $6,655 $6,540 $23,529 

Well Site Program Weighted Averageh $5,298 $19,058 

Gathering and Boosting Statione 34.1 9.48 $30,907 $61,898 $53,996 $1,816 $6,532 Transmission Statione 60.5 1.67 $30,907 $61,898 $61,898 $1,023 $36,969 Storage Facilitye 159.5 4.41 $30,907 $61,898 $61,898 $388 $14,024 

Compressor Station Weighted Average $1,722 $7,586 

a. Assumes 72% reduction with the implementation of repair threshold of 10,000 ppm, 92% reduction for 2,500 ppm and 97% for 500 ppm monitoring. b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divid22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost of implemprogram of $30,907. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas 

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $4,238 for 10,000 ppm repair threshold, $6,320 for 2,500 ppm and amortization of the capital cost over 8 years at 7% interest. e. Annual cost for compressor stations (i.e., gathering and boosting, transmission and storage) includes annual monitoring and repair cost repair threshold, $51,609 for 2,500 ppm and $61,8988 for 500 ppm and amortization of the capital cost over 8 years at 7% interest. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as tleaks was not estimated for the transmission or storage segment. 
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Table 5-24. Summary of the Model Plant Cost of Control for the Quarterly Method 21 Monitoring and Rep

Pollutant 

Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

10,000 ppm

Natural Gas Production Well Sited 3.04 0.85 $1,460 $5,407 $4,702 $1,778 $6,396 Oil Production Well Sited 0.36 0.20 $1,460 $5,407 $5,238 $15,066 $26,696 

Well Site Program Weighted Averageh $11,746 $21,623 

Gathering and Boosting Station 23.5 6.55 $30,907 $39,978 $34,519 $1,698 $6,108 Transmission Station 41.8 1.16 $30,907 $39,978 $39,978 $957 $34,568 Storage Facility 110.2 3.05 $30,907 $39,978 $39,978 $363 $13,113 

Compressor Station Weighted Average $1,610 $7,093 

2,500 ppm

Natural Gas Production Well Sited 4.04 1.12 $1,460 $7,490 $6,553 $1,854 $6,669 Oil Production Well Sited 0.97 0.27 $1,460 $7,490 $7,265 $7,738 $27,838 

Well Site Program Weighted Averageh $6,268 $22,548 

Gathering and Boosting Station 31.3 8.69 $30,907 $58,635 $51,385 $1,875 $6,744 Transmission Station 55.5 1.54 $30,907 $58,635 $58,635 $1,056 $38,168 Storage Facility 146.3 4.05 $30,907 $58,635 $58,635 $401 $14,479 

Compressor Station Weighted Average $1,778 $7,832 

500 ppm
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Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

Natural Gas Production Well Sited 4.27 1.19 $1,460 $7,824 $6,835 $1,834 $6,597 Oil Production Well Sited 1.02 0.28 $1,460 $7,824 $7,587 $7,654 $27,534 

Well Site Program Weighted Averageh $6,199 $22,302 

Gathering and Boosting Station 33.0 9.18 $30,907 $63,747 $56,090 $1,930 $6,942 Transmission Station 58.6 1.62 $30,907 $63,747 $63,747 $1,087 $39,288 Storage Facility 154.6 4.28 $30,907 $63,747 $63,747 $412 $14,904 

Compressor Station Weighted Average $1,830 $8,062 

a. Assumes 67% reduction with the implementation of repair threshold of 10,000 ppm, 89% reduction for 2,500 ppm and 94% for 500 ppm monitoring. b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divid22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost of implemprogram of $30,907. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas 

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $5,163 for 10,000 ppm repair threshold, $7,245 for 2,500 ppm and amortization of the capital cost over 8 years at 7% interest. e. Annual cost for compressor stations (i.e., gathering and boosting, transmission and storage) includes annual monitoring and repair cost repair threshold, $53,459 for 2,500 ppm and $63,747 for 500 ppm and amortization of the capital cost over 8 years at 7% interest. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as tleaks was not estimated for the transmission or storage segment. 
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Table 5-25. Summary of the Model Plant Cost of Control for the Annual Method 21 Monitoring and Repa

Pollutant 

Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

10,000 ppm

Natural Gas Production Well Sited 3.72 1.03 $1,460 $4,020 $3,157 $540 $1,943 Oil Production Well Sited 0.73 0.20 $1,460 $4,020 $3,813 $2,758 $9,924 

Well Site Program Weighted Averageh $2,204 $7,929 

Gathering and Boosting Station 28.8 8.01 $30,907 $37,203 $30,523 $646 $2,322 Transmission Station 51.1 1.42 $30,907 $37,203 $37,203 $364 $13,142 Storage Facility 134.8 3.73 $30,907 $37,203 $37,203 $138 $4,985 

Compressor Station Weighted Average $612 $2,697 

2,500 ppm

Natural Gas Production Well Sited 4.27 1.19 $1,460 $6,103 $5,113 $715 $2,573 Oil Production Well Sited 1.02 0.28 $1,460 $6,103 $5,866 $2,985 $10,738 

Well Site Program Weighted Averageh $2,418 $8,697 

Gathering and Boosting Station 33.0 9.18 $30,907 $55,860 $48,203 $845 $3,042 Transmission Station 58.6 1.62 $30,907 $55,860 $55,860 $476 $17,214 Storage Facility 154.6 4.28 $30,907 $55,860 $55,860 $181 $6,530 

Compressor Station Weighted Average $802 $3,532 
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Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

500 ppm

Natural Gas Production Well Sited 4.45 1.24 $1,460 $6,437 $5,406 $724 $2,603 Oil Production Well Sited 1.07 0.30 $1,460 $6,437 $6,190 $3,020 $10,864 

Well Site Program Weighted Averageh $2,446 $8,799 

Gathering and Boosting Station 34.4 9.57 $30,907 $60,973 $52,990 $885 $3,185 Transmission Station 61.1 1.69 $30,907 $60,973 $60,973 $499 $18,022 Storage Facility 161.1 4.46 $30,907 $60,973 $60,973 $189 $6,837 

Compressor Station Weighted Average $840 $3,698 

a. Assumes 82% reduction with the implementation of repair threshold of 10,000 ppm, 94% reduction for 2,500 ppm and 98% for 500 ppm monitoring. b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divid22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost of implemprogram of $30,907. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas 

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $3,775 for 10,000 ppm repair threshold, $5,858 for 2,500 ppm and amortization of the capital cost over 8 years at 7% interest. e. Annual cost for compressor stations (i.e., gathering and boosting, transmission and storage) includes annual monitoring and repair cost repair threshold, $50,685 for 2,500 ppm and $55,973 for 500 ppm and amortization of the capital cost over 8 years at 7% interest. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as tleaks was not estimated for the transmission or storage segment. . 
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Table 5-26. Summary of the Model Plant Cost of Control for the Semiannual Method 21 Monitoring and Re

Pollutant 

Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

10,000 ppm

Natural Gas Production Well Sited 3.27 0.91 $1,460 $4,482 $3,725 $686 $2,467 Oil Production Well Sited 0.78 0.22 $1,460 $4,482 $4,301 $2,862 $10,297 

Well Site Program Weighted Averageh $2,318 $8,340 

Gathering and Boosting Station 25.3 7.03 $30,907 $38,128 $32,263 $753 $2,710 Transmission Station 44.9 1.24 $30,907 $38,128 $38,128 $425 $15,339 Storage Facility 118.4 3.28 $30,907 $38,128 $38,128 $161 $5,819 

Compressor Station Weighted Average $715 $3,148 

2,500 ppm

Natural Gas Production Well Sited 4.18 1.16 $1,460 $6,565 $5,597 $786 $2,828 Oil Production Well Sited 1.00 0.28 $1,460 $6,565 $6,333 $3,281 $11,802 

Well Site Program Weighted Averageh $2,657 $9,560 

Gathering and Boosting Station 32.3 8.99 $30,907 $56,785 $49,291 $878 $3,159 Transmission Station 57.4 1.59 $30,907 $56,785 $56,785 $495 $17,879 Storage Facility 151.3 4.19 $30,907 $56,785 $56,785 $188 $6,782 

Compressor Station Weighted Average $833 $3,669 
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Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

500 ppm

Natural Gas Production Well Sited 4.40 1.22 $1,460 $6,899 $5,879 $783 $2,819 Oil Production Well Sited 1.05 0.29 $1,460 $6,899 $6,655 $3,270 $11,764 

Well Site Program Weighted Averageh $2,649 $9,529 

Gathering and Boosting Station 34.1 9.48 $30,907 $61,898 $53,996 $908 $3,266 Transmission Station 60.5 1.67 $30,907 $61,898 $61,898 $512 $18,484 Storage Facility 159.5 4.41 $30,907 $61,898 $61,898 $194 $7,012 

Compressor Station Weighted Average $861 $3,793 

a. Assumes 72% reduction with the implementation of repair threshold of 10,000 ppm, 92% reduction for 2,500 ppm and 97% for 500 ppm monitoring. b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divid22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost of implemprogram of $30,907. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas 

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $4,238 for 10,000 ppm repair threshold, $6,320 for 2,500 ppm and amortization of the capital cost over 8 years at 7% interest. e. Annual cost for compressor stations (i.e., gathering and boosting, transmission and storage) includes annual monitoring and repair cost repair threshold, $51,609 for 2,500 ppm and $61,8988 for 500 ppm and amortization of the capital cost over 8 years at 7% interest. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as tleaks was not estimated for the transmission or storage segment. 
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Table 5-27. Summary of the Model Plant Cost of Control for the Quarterly Method 21 Monitoring and Rep

Pollutant 

Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

10,000 ppm

Natural Gas Production Well Sited 3.04 0.85 $1,460 $5,407 $4,702 $889 $3,198 Oil Production Well Sited 0.36 0.20 $1,460 $5,407 $5,238 $7,533 $13,348 

Well Site Program Weighted Averageh $5,873 $10,811 

Gathering and Boosting Station 23.5 6.55 $30,907 $39,978 $34,519 $849 $3,054 Transmission Station 41.8 1.16 $30,907 $39,978 $39,978 $478 $17,284 Storage Facility 110.2 3.05 $30,907 $39,978 $39,978 $181 $6,557 

Compressor Station Weighted Average $805 $3,547 

2,500 ppm

Natural Gas Production Well Sited 4.04 1.12 $1,460 $7,490 $6,553 $927 $3,335 Oil Production Well Sited 0.97 0.27 $1,460 $7,490 $7,265 $3,869 $13,919 

Well Site Program Weighted Averageh $3,134 $11,274 

Gathering and Boosting Station 31.3 8.69 $30,907 $58,635 $51,385 $937 $3,372 Transmission Station 55.5 1.54 $30,907 $58,635 $58,635 $528 $19,084 Storage Facility 146.3 4.05 $30,907 $58,635 $58,635 $200 $7,239 

Compressor Station Weighted Average $889 $3,916 
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Model Plant 

Annual Emission 

Reductionsa

(tpy) 

Capital 

Costb

($) 

Annual Cost 

($/year) 

Cost of Control 

(without savings) 

($/ton) 

CH4 VOC without savings with savings CH4 VOC 

500 ppm

Natural Gas Production Well Sited 4.27 1.19 $1,460 $7,824 $6,835 $917 $3,298 Oil Production Well Sited 1.02 0.28 $1,460 $7,824 $7,587 $3,827 $13,767 

Well Site Program Weighted Averageh $3,100 $11,151 

Gathering and Boosting Station 33.0 9.18 $30,907 $63,747 $56,090 $965 $3,471 Transmission Station 58.6 1.62 $30,907 $63,747 $63,747 $544 $19,644 Storage Facility 154.6 4.28 $30,907 $63,747 $63,747 $206 $7,452 

Compressor Station Weighted Average $915 $4,031 

a. Assumes 67% reduction with the implementation of repair threshold of 10,000 ppm, 89% reduction for 2,500 ppm and 94% for 500 ppm monitoring. b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divid22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost of implemprogram of $30,907. c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assuming natural gas 

reductions, CH4 as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. 

d. Annual cost for well sites includes annual monitoring and repair cost of $5,163 for 10,000 ppm repair threshold, $7,245 for 2,500 ppm and amortization of the capital cost over 8 years at 7% interest. e. Annual cost for compressor stations (i.e., gathering and boosting, transmission and storage) includes annual monitoring and repair cost repair threshold, $53,459 for 2,500 ppm and $63,747 for 500 ppm and amortization of the capital cost over 8 years at 7% interest. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as tleaks was not estimated for the transmission or storage segment. 
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5.5 Regulatory Options 

Monitoring and repair of fugitive emissions components using OGI or Method 21 is believed to be 

the most viable methods for reducing fugitive emissions. Therefore, the following regulatory options were 

considered for reducing fugitive emissions from oil and natural gas production well sites, gathering and 

boosting stations, transmission stations, and storage facilities: 

 Regulatory Option 1. Require the implementation of a fugitive emissions monitoring and repair 

program using OGI. The sub-options that we evaluated for a fugitive emissions monitoring and 

repair program using OGI are based on three monitoring frequencies; annual, semiannual and 

quarterly) as shown below. 

o Regulatory Option 1a - Conducting monitoring and repair on an annual frequency. 

o Regulatory Option 1b - Conducting monitoring and repair on a semiannual frequency. 

o Regulatory Option 1c - Conducting monitoring and repair on a quarterly frequency. 

 Regulatory Option 2. Require the implementation of a monitoring and repair program using 

Method 21. The sub-options for a fugitive emissions monitoring and repair program using Method 

21 are based on the combination of three monitoring frequencies (annual, semiannual and 

quarterly) and three leak repair thresholds (10,000 ppm, 2,500 ppm and 500 ppm). The sub-options 

shown below summarize those possible combinations. 

o Regulatory Option 2a -500 - Conducting monitoring and repair on an annual frequency 

with a repair threshold level of 500 ppm. 

o Regulatory Option 2a -2500 - Conducting Method 21 monitoring and repair on an annual 

frequency with a repair threshold level of 2,500 ppm. 

o Regulatory Option 2a -10,000 - Conducting Method 21 monitoring and repair on an annual 

frequency with a repair threshold level of 10,000 ppm. 

o Regulatory Option 2b -500 - Conducting Method 21 monitoring and repair on a semiannual 

frequency with a repair threshold level of 500 ppm. 

o Regulatory Option 2b -2500 - Conducting Method 21 monitoring and repair on a 

semiannual frequency with a repair threshold level of 2,500 ppm. 

o Regulatory Option 2b -10,000 - Conducting Method 21 monitoring and repair on a 

semiannual frequency with a repair threshold level of 10,000 ppm. 

o Regulatory Option 2c -500 - Conducting Method 21 monitoring and repair on a quarterly 

frequency with a repair threshold level of 500 ppm. 
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o Regulatory Option 2c -2500 - Conducting Method 21 monitoring and repair on a quarterly 

frequency with a repair threshold level of 2,500 ppm. 

o Regulatory Option 2c -10,000 - Conducting Method 21 monitoring and repair on a 

quarterly frequency with a repair threshold level of 10,000 ppm. 

5.5.1 Evaluation of Regulatory Options for Fugitive Emissions 

5.5.1.1 Option 1 Based on OGI Monitoring 

As noted above, we calculated a weighted average cost of control for well sites (which includes oil 

and gas production well sites) and compressor stations (which includes gathering and boosting stations, 

transmission stations and storage facilities). For ease of review we have summarized the cost of control for 

the sub-options for Option 1 for well sites and compressor stations in Table 5-28. 

Well Sites 

For well sites, we have three sub-options based on the frequency of OGI monitoring conducted. 

For Option 1a, based on an annual frequency, the single-pollutant cost of control, without considering 

savings for gas recovery was calculated to be $2,475 per ton of CH4 and $8,903 per ton of VOC. The 

multi-pollutant cost of control, without considering savings for gas recovery was calculated to be $1,237 

per ton of CH4 and $4,451 per ton of VOC. Option 1b based on a semiannual frequency, the singlepollutant cost of control, without considering savings for gas recovery was calculated to be $2,768 per ton 

of CH4 and $9,958 per ton of VOC. The multi-pollutant cost of control, without considering savings for 

gas recovery was calculated to be $1,384 per ton of CH4 and $4,979 per ton of VOC. Option 1c, based on 

a quarterly frequency, the single-pollutant cost of control, without considering savings for gas recovery 

was calculated to be $3,753 per ton of CH4 and $13,502 per ton of VOC. The multi-pollutant cost of 

control, without considering savings for gas recovery was calculated to be $1,877 per ton of CH4 and 

$6,751 per ton of VOC. 

If we consider gas savings, the cost are reduced based on the gas considered to have not been lost. 

For Option 1a, based on an annual frequency, the single-pollutant cost of control, considering savings for 

gas recovery was calculated to be $2,243 per ton of CH4 and $8,069 per ton of VOC. The multi-pollutant 

cost of control, considering savings for gas recovery was calculated to be $1,121 per ton of CH4 and 

$4,035 per ton of VOC. Option 1b, based on a semiannual frequency, the single-pollutant cost of control, 

without considering savings for gas recovery was calculated to be $2,536 per ton of CH4 and $9,124 per 

ton of VOC. The multi-pollutant cost of control, considering savings for gas recovery was calculated to be 

$1,268 per ton of CH4 and $4,562 per ton of VOC. Option 1c, based on a quarterly frequency, the single-
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pollutant cost of control, considering savings for gas recovery was calculated to be $3,521 per ton of CH4

and $12,668 per ton of VOC. The multi-pollutant cost of control, considering savings for gas recovery was 

calculated to be $1,761 per ton of CH4 and $6,334 per ton of VOC. 

Compressor Stations 

For compressor stations we have three sub-options based on the frequency of OGI monitoring 

conducted. Based on an annual frequency (option 1a), the single-pollutant cost of control, without 

consideration of savings for gas recovery, was calculated to be $686 per ton of CH4 and $3,110 per ton of 

VOC. The multi-pollutant cost of control, without considering savings for gas recovery was calculated to 

be $343 per ton of CH4 and $1,555 per ton of VOC. Based on a semiannual frequency (option 1b), the 

single-pollutant cost of control, without consideration of savings for gas recovery, was calculated to be 

$718 per ton of CH4 and $3,281 per ton of VOC. The multi-pollutant cost of control, without considering 

savings for gas recovery was calculated to be $359 per ton of CH4 and $1,641per ton of VOC. Based on a 

quarterly frequency (option 1c), the single-pollutant cost of control, without consideration of savings for 

gas recovery, was calculated to be $930 per ton of CH4 and $4,273 per ton of VOC. The multi-pollutant 

cost of control, without considering savings for gas recovery was calculated to be $465 per ton of CH4 and 

$2,136 per ton of VOC. 

Because the gas handled by transmission and storage facilities is not typically owned by these 

facilities, we do not consider the value of the gas saved as an offset to the cost. However, for gathering and 

boosting stations, the gas savings could be considered. Therefore, we calculated the cost of control for 

compressor stations considering the gas savings contributed by gathering and bosting stations. Based on an 

annual frequency (option 1a), the single-pollutant cost of control, with consideration of savings for gas 

recovery, was calculated to be $471 per ton of CH4 and $2,338 per ton of VOC. The multi-pollutant cost 

of control, considering savings for gas recovery was calculated to be $236 per ton of CH4 and $1,169 per 

ton of VOC. Based on a semiannual frequency (option 1b), the single-pollutant cost of control, with 

consideration of savings for gas recovery, was calculated to be $504 per ton of CH4 and $2,510 per ton of 

VOC. The multi-pollutant cost of control, considering savings for gas recovery was calculated to be $252 

per ton of CH4 and $1,255 per ton of VOC. And based on a quarterly frequency (option 1c), the singlepollutant cost of control, with consideration of savings for gas recovery, was calculated to be $715 per ton 

of CH4 and $3,502 per ton of VOC. The multi-pollutant cost of control, considering savings for gas 

recovery was calculated to be $358 per ton of CH4 and $1,751 per ton of VOC. 
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We also evaluated the reasonableness of the burden to industry for the three options with the 

respective reductions and costs. We determined that the quarterly monitoring frequency was too costly for 

most segments and would be considered overly burdensome given the additional level of emissions 

reductions. Annual and semiannual monitoring appeared to have reasonable associated costs. Therefore, 

our analysis of nationwide impacts considered options 1a (annual monitoring) and 1b (semiannual 

monitoring) as OGI monitoring and repair plan options for the NSPS. 
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Table 5-28. Summary of the Cost of Control for Sub Options of Option 1 Based on OGI Mo

Option 

Cost of Control 

(without gas savings) 

Cost of Contr

(with gas savin

Single-Pollutant 

($/ton) 

Multi-Pollutant 

($/ton) 

Single-Pollutant 

 ($/ton) 

Methane VOC Methane VOC Methane VOC Me

Well Sites 

1a - Annual $2,475 $8,903 $1,237 $4,451 $2,243 $8,069 $11b - Semiannual $2,768 $9,958 $1,384 $4,979 $2,536 $9,124 $11c - Quarterly $3,753 $13,502 $1,877 $6,751 $3,521 $12,668 $1

Compressor Stations 

1a - Annual $686 $3,110 $343 $1,555 $471 $2,338 $1b - Semiannual $718 $3,281 $359 $1,641 $504 $2,510 $1c - Quarterly $930 $4,273 $465 $2,136 $715 $3,502 $
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5.5.1.2 Option 2 - Based on Method 21 Monitoring and Three Leak Repair Thresholds 

As noted above, we calculated a weighted average cost of control for well sites (which includes oil 

and gas production well sites) and compressor stations (which includes gathering and boosting stations, 

transmission stations and storage facilities) for nine Method 21 monitoring and repair plan sub-options 

based on the combination of monitoring frequency (annual, semiannual and quarterly) and three potential 

repair thresholds (10,000 ppm, 2,500 ppm and 500 ppm). For ease of review we have summarized the cost 

of control for the sub-options for Option 4 for well sites and compressor stations in Table 5-29. 

Our analysis of the cost of control for the various options, using both the single-pollutant and 

multi-pollutant cost approaches, indicates that these cost of control generally increases with increasing 

monitoring frequency (i.e., quarterly monitoring has a higher cost of control that annual monitoring) and 

increase with decreasing fugitive emissions repair threshold (i.e., 500 ppm results in a higher cost of 

control than 10,000 ppm). 

Well Sites 

For well sites, the cost of control under the single-pollutant method (i.e., all cost attributed to 

methane and VOC individually), and without considering gas savings, was determined to range from 

$4,408 (annual frequency at 10,000 ppm repair threshold) to $6,199 (quarterly frequency at 500 ppm 

repair threshold per ton of methane and $15,858 to $22,302 per ton of VOC. Under the multi-pollutant 

method, (i.e., 50 percent of the cost attributed to methane and 50 percent attributed to VOC), and without 

considering gas savings, was determined to be from $2,204 to $3,100 per ton of methane and $7,929 to 

$11,151 per ton of VOC. 

If we consider gas savings, the cost are reduced based on the gas considered to have not been lost. 

When we consider gas savings, under the single-pollutant method, the cost of control was found to range 

from $4,137 to $ 5,968 per ton of methane and $14,884 to $21,468 per ton of VOC, and under the multipollutant method $2,069 to $2,984 per ton of methane and $7,442 to $10,734 per ton of VOC. 

Compressor Stations 

For compressor stations (which includes gathering and boosting, transmission and storage), the 

cost of control under the single-pollutant method (i.e., all cost attributed to methane and VOC 

individually), and without considering gas savings, was determined to range from $1,225 (annual 

frequency at 10,000 ppm repair threshold) to $1,830 (quarterly frequency at 500 ppm repair threshold per 

ton of methane and $5,393 to $8,062 per ton of VOC. Under the multi-pollutant method, (i.e., 50 percent 
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of the cost attributed to methane and 50 percent attributed to VOC), and without considering gas savings, 

was determined to be from $612 to $915 per ton of methane and $2,697 to $4,031 per ton of VOC. 

Because the gas handled by transmission and storage facilities is not typically owned by these 

facilities, we do not consider the value of the gas saved as an offset to the cost. However, for gathering and 

boosting stations, the gas savings could be considered. Therefore, we calculated the cost of control for 

compressor stations considering the gas savings contributed by gathering and boosting stations. If we 

consider gas savings, the cost are reduced based on the gas considered to have not been lost. For 

compressor stations, when we consider gas savings, under the single-pollutant method, the cost of control 

was found to range from $1,010 to $ 1,616 per ton of methane and $4,622 to $7,290 per ton of VOC, and 

under the multi-pollutant method $505 to $808 per ton of methane and $2,311 to $3,645 per ton of VOC. 

As with OGI monitoring, we also evaluated the reasonableness of the burden to industry for the 

three options with the respective reductions and costs. We determined that the quarterly monitoring 

frequency was too costly for most segments and would be considered overly burdensome given the 

additional level of emissions reductions. In addition, we determined that the 500 ppm leak repair threshold 

was too costly for these segments and have eliminated this option from each of the monitoring 

frequencies. Annual and semiannual monitoring appeared to have reasonable associated costs. Therefore, 

our analysis of nationwide impacts considered the two sub-options for 2a (annual monitoring at the 10,000 

and 2,500 ppm repair thresholds) and the two sub-options for option 2b (semiannual monitoring at the 

10,000 and 2,500 ppm repair thresholds) as viable Method 21 monitoring and repair plan options for the 

NSPS. 
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Table 5-29. Summary of the Cost of Control for Sub Options of Option 2 Based on Method 21 Monitori

Thresholds 

Option 

Cost of Control 

(without gas savings) 

Cost of Con

(with gas sav

Single-Pollutant 

($/ton) 

Multi-Pollutant 

($/ton) 

Single-Pollutant 

 ($/ton) 

Methane VOC Methane VOC Methane VOC M

Well Sites 

2a - Annual, 10,000 ppm $4,408 $15,858 $2,204 $7,929 $4,137 $14,884 2a - Annual, 2,500 ppm $4,835 $17,394 $2,418 $8,697 $4,603 $16,560 2a - Annual, 500 ppm $4,892 $17,599 $2,446 $8,799 $4,660 $16,765 2b - Semiannual, 10,000 ppm $4,637 $16,680 $2,318 $8,340 $4,405 $15,846 2b - Semiannual, 2,500 ppm $5,315 $19,119 $2,657 $9,560 $5,083 $18,285 2b - Semiannual, 500 $5,298 $19,058 $2,649 $9,529 $5,066 $18,224 2c - Quarterly, 10,000 ppm $11,746 $21,623 $5,873 $10,811 $11,335 $20,789 2c - Quarterly, 2,500 ppm $6,268 $22,548 $3,134 $11,274 $6,036 $21,714 2c - Quarterly, 500 ppm $6,199 $22,302 $3,100 $11,151 $5,968 $21,468 

Compressor Stations 

2a - Annual, 10,000 ppm $1,225 $5,393 $612 $2,697 $1,010 $4,622 2a - Annual, 2,500 ppm $1,604 $7,064 $802 $3,532 $1,390 $6,293 2a - Annual, 500 ppm $1,679 $7,396 $840 $3,698 $1,465 $6,625 2b - Semiannual, 10,000 ppm $1,429 $6,295 $715 $3,148 $1,215 $5,524 2b - Semiannual, 2,500 ppm $1,666 $7,337 $833 $3,669 $1,452 $6,566 2b - Semiannual, 500 ppm $1,722 $7,586 $861 $3,793 $1,508 $6,814 2c - Quarterly, 10,000 ppm $1,610 $7,093 $805 $3,547 $1,396 $6,322 2c - Quarterly, 2,500 ppm $1,778 $7,832 $889 $3,916 $1,564 $7,060 2c - Quarterly, 500 ppm $1,830 $8,062 $915 $4,031 $1,616 $7,290 
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5.5.2 Nationwide Impacts of Regulatory Options 

This section provides an analysis of the primary environmental impacts (i.e., emission reductions), 

cost impacts and secondary environmental impacts related to Regulatory Option, which was selected as a 

viable option for reducing fugitive emissions from fugitive emissions components located at production 

well sites and compressor stations. 

5.5.2.1 Primary Environmental Impacts of Regulatory Options 

Based on the discussion above, we consider Regulatory Option 1a, 1b, 2a (with a repair threshold 

of 2,500 ppm or 10,000 ppm) and 2b (with a repair threshold of 2,500 ppm or 10,000 ppm) for further 

consideration in setting standards for fugitive emissions from production well sites compressor stations. 

 Regulatory Option 1a. Require the implementation of a fugitive emissions monitoring and repair 

program which includes annual monitoring of fugitive emissions components using OGI. 

 Regulatory Option 1b. Require the implementation of a fugitive emissions monitoring and repair 

program which includes semiannual monitoring of fugitive emissions and components using OGI. 

 Regulatory Option 2a - (2,500 ppm) - Require the implementation of a Method 21 monitoring and 

repair program which includes annual monitoring of fugitive emissions and components using 

Method 21 with a 2,500 ppm repair threshold. 

 Regulatory Option 2a - (10,000 ppm) - Require the implementation of a Method 21 monitoring and 

repair program which includes annual monitoring of fugitive emissions and components using 

Method 21 with a 10,000 ppm repair threshold. 

 Regulatory Option 2b - (2,500 ppm) - Require the implementation of a Method 21 monitoring and 

repair program which includes semiannual monitoring of fugitive emissions and components using 

Method 21 with a 2,500 ppm repair threshold. 

 Regulatory Option 2b - (10,000 ppm) - Require the implementation of a Method 21 monitoring and 

repair program which includes semiannual monitoring of fugitive emissions and components using 

Method 21 with a 10,000 ppm repair threshold. 

The number of oil and natural production well sites, gathering and boosting stations, transmission 

stations, and storage facilities that would be subject to the regulatory options listed above were presented 

in Table 5-10. In 2020, it was estimated that there would be 16,562 uncontrolled oil well sites, 5,518 

uncontrolled gas well sites, 259 uncontrolled gathering and boosting stations, 6 uncontrolled transmission 

stations, and 15 uncontrolled storage facilities subject to these options. In 2025, it was estimated that there 
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would be 100,175 uncontrolled oil well sites, 38,393 uncontrolled gas well sites, 1,554 uncontrolled 

gathering and boosting stations, 36 uncontrolled transmission stations, and 90 uncontrolled storage 

facilities subject to these options. 

It was estimated that OGI monitoring and repair on an annual frequency can achieve an overall 40 

percent VOC and CH4 reduction over the life span of the facility and on a semiannual frequency can 

achieve an overall 60 percent VOC and CH4 reduction. These percent reduction values were estimated 

based on information from the EPA white paper and an analysis by the Colorado Air Quality Control 

Commission. Nationwide emission reductions were estimated by applying this 40 and 60 percent VOC 

and CH4 reduction to the uncontrolled baseline emissions presented in Table 5-11. In considering the two 

frequency options, we considered the implementation issues with respect to the monitoring and repair plan 

and we determined that, based on input from industry and regulatory agencies, that the program frequency 

should be consistent across the segments in the oil and natural gas source category. Therefore, nationwide 

impacts were estimated for both of these options as presented in Tables 5-30 and 5-31. 

It was estimated that Method 21 monitoring and repair can achieve a range of VOC and CH4

depending on the frequency of monitoring combined with the leak repair threshold. The percent reductions 

as presented in Table 5-18 range from 72 percent (semiannual frequency with 10,000 ppm leak repair 

threshold) to 98 percent (annual frequency with a 500 ppm leak repair threshold). These percent reductions 

were estimated using leak definition and monitoring frequency SOCMI emission factor data from the EPA 

Equipment Leak Protocol document. Nationwide emission reductions were estimated by applying these 

percent to the uncontrolled baseline emissions VOC and CH4 emissions presented in Table 5-19. The 

nationwide impacts were estimated for six sub-options (2a and 2b sub-options) as presented in Tables 5-32 

and 5-33. 

5.5.2.2 Cost Impacts 

OGI Monitoring and Repair Plans (options 1a and 1b) 

The operational standards for Regulatory Option 1a include both annual monitoring of fugitive 

emissions components using OGI and repair of fugitive emissions components that are found to be leaking 

during the survey. The annual costs for these surveys (as summarized in Table 5-30) are estimated to be 

$1,329 for oil and natural gas production well sites, $10,124 for gathering and boosting stations, $10,049 

for transmission stations, and $13,634 for storage facilities, which includes the costs for having a 

subcontractor do the semiannual OGI survey, activities planning, repair costs, resurvey of repaired 

components using a Method 21 device, preparation and submittal of an annual report and the amortization 
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of the capital costs over 8 years at 7 percent interest. The potential natural gas saved from the 

implementation of a semiannual OGI monitoring and repair program was calculated to be 105 thousand 

standard cubic feet per year (Mscf/yr) for a natural gas production well site and 25 Mscf/yr for an oil 

production well site. For the compressor stations, the potential natural gas saved was calculated to be 815 

Mscf/yr for gathering and boosting stations, 1,292 Mscf/yr for transmission stations, and 3,405 Mscf/yr for 

storage facilities.57 However, the value of the natural gas saved is not considered as an offset to costs for 

transmission and storage because we assume that operators of these facilities do not own the natural gas 

handled. 

The operational standards for Regulatory Option 1b include both semiannual monitoring of 

fugitive emissions components using OGI and repair of fugitive emissions components that are found to 

be leaking during the survey. The annual costs for these surveys (as summarized in Table 5-31) are 

estimated to be $2,230 for oil and natural gas production well sites, $15,881 for gathering and boosting 

stations, $15,732 for transmission stations, and $22,902 for storage facilities, which includes the costs for 

having a subcontractor do the semiannual OGI survey, activities planning, repair costs, preparation and 

submittal of an annual report and the amortization of the capital costs over 8 years at 7 percent interest. 

The potential natural gas savings from the implementation of a semiannual OGI monitoring and repair 

program were calculated to be 158 thousand standard cubic feet per year (Mscf/yr) for a natural gas 

production well site and 38 Mscf/yr for an oil production well site. For the compressor stations, the 

potential natural gas savings were calculated to be 1,222 Mscf/yr for gathering and boosting stations, 

1,937 Mscf/yr for transmission stations, and 5,107 Mscf/yr for storage facilities.58 

Applying the cost for the annual OGI monitoring and repair (Option 1a) to the estimated 16,562 oil 

production well sites and 5,518 natural gas production well sites in projected year 2020, the total 

nationwide costs were estimated to be $25.4 million, which includes an estimated annual savings of $4 

million when natural gas savings are considered. Likewise, for projected year 2025, for 100,175 oil 

production well sites and 38,933 natural gas production well sites, the total nationwide cost was estimated 

to be $158.4 million, including annual savings estimated around $26.5 million when natural gas savings 

are considered. For the 259 new gathering and boosting, 6 transmission and 15 storage compressor 

stations, the nationwide costs were estimated to be $2 million in the year 2020, which includes annual 

savings of $0.8 million per year for gathering and boosting stations. For the 1,554 new gathering and 

                                                            

57 Natural gas savings calculated using the CH4 reductions and assuming a methane to natural gas volume ration of 82.9% for 

upstream facilities (well sites, gathering & boosting) and a methane to natural gas volume ratio of 92.8% for downstream 

facilities (transmission, storage).

58 Ibid.
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boosting, 36 transmission and 90 storage facilities, the nationwide costs were estimated to be $12.3 million 

in the year 2025. Annual savings were estimated to be $5 million per year for gathering and boosting 

stations. No annual savings were estimated for transmission and storage facilities, because they do not 

own the natural gas that is compressed at their facilities. Table 5-30 summarizes the nationwide cost 

impacts for the projected years 2020 and 2025 for implementation of regulatory Option 1a. 

Applying the cost for the semiannual OGI monitoring and repair to the estimated 16,562 oil 

production well sites and 5,518 natural gas production well sites in projected year 2020, the total 

nationwide costs were estimated to be $43.2 million, which includes an estimated annual savings of $6 

million when natural gas savings are considered. Likewise, for projected year 2025, for 100,175 oil 

production well sites and 38,933 natural gas production well sites, the total nationwide cost was estimated 

to be $270.5 million, including annual savings estimated around $39.7 million when natural gas savings 

are considered. For compressor stations, which include 259 new gathering and boosting, 6 transmission 

and 15 storage facilities, the nationwide costs were estimated to be $3.3 million in the year 2020. Annual 

savings were estimated to be $1.3 million per year for gathering and boosting stations. For 1,554 new 

gathering and boosting, 36 transmission and 90 storage facilities, and the nationwide costs were estimated 

to be $19.7 million in the projected year 2025. Annual savings were estimated to be $7.6 million per year 

for gathering and boosting stations. No annual savings were estimated for transmission and storage 

facilities, because they do not own the natural gas that is compressed at their facilities. Table 5-31 

summarizes the nationwide cost impacts for the projected years 2020 and 2025 for implementation of 

regulatory Option 1b. 

Method 21 Monitoring and Repair Plans (Options 2a and 2b) 

The operational standards for Regulatory Option 2a include both annual monitoring of fugitive 

emissions components using Method 21 and repair of fugitive emissions components that are found to be 

leaking during the survey. The two sub-options considered included leak repair thresholds of 10,000 ppm 

and 2,500 ppm. Without considering gas savings, the estimated annual costs for these surveys are 

estimated to range from $4,020 (annual at 10,000 ppm repair threshold) to $6,103 (semiannual at 2,500 

ppm repair threshold) for oil and natural gas production well sites and from $37,203 to $55,860 for 

gathering and boosting, transmission and storage compressor stations. This cost includes the costs for 

conducting the Method21 survey, activities planning, repair costs, resurvey after repair, preparation and 

submittal of an annual report and the amortization of the capital costs over 8 years at 7 percent interest. 

The potential natural gas savings from the implementation of a Method21 monitoring and repair program 

were calculated to range from 189 thousand standard cubic feet per year (Mscf/yr) to 247 Mcf/yr for a 
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natural gas production well site, from 45 to 59 Mscf/yr for an oil production well site, and 1,466 to 1,914 

Mcf/yr for gathering and boosting compressor stations. The potential natural gas savings were calculated 

to range from 2,325 Mcf/yr to 3,035 Mcf/yr for transmission compressor stations and from 6,129 to 8,001 

Mcf/yr for storage facility compressor stations. However, because gas handled by transmission and storage 

facilities is not typically owned by the operator, we do not consider this as gas saved with respect to 

offsetting of costs. 

Applying the cost for the annual Method 21 monitoring and 10,000 ppm repair threshold to the 

estimated 16,562 oil production well sites and 5,518 natural gas production well sites in projected year 

2020, the total nationwide costs were estimated to be $80.6 million, which includes an estimated annual 

savings of $8.2 million when natural gas savings are considered. Likewise, for projected year 2025, for 

100,175 oil production well sites and 38,933 natural gas production well sites, the total nationwide cost 

was estimated to be $504.9 million, including annual savings estimated around $54.3 million when natural 

gas savings are considered. For compressor stations, the nationwide costs for 2020 for this option were 

estimated to be $8.7 million, including $1.7 million when natural gas savings are considered. For 2025 for 

compressor stations the nationwide costs for 2020 were estimated to be $52.1 million, including $10.4 

million when natural gas savings are considered. 

Applying the cost for the annual Method 21 monitoring and 2,500 ppm repair threshold to the 

estimated 16,562 oil production well sites and 5,518 natural gas production well sites in projected year 

2020, the total nationwide costs were estimated to be $125.4 million, which includes an estimated annual 

savings of $9.4 million when natural gas savings are considered. Likewise, for projected year 2025, for 

100,175 oil production well sites and 38,933 natural gas production well sites, the total nationwide cost 

was estimated to be $786.7 million, including annual savings estimated around $62.2 million when natural 

gas savings are considered. For compressor stations, the nationwide costs for 2020 for this option were 

estimated to be $13.7 million, including $2 million when natural gas savings are considered. For 2025 for 

compressor stations the nationwide costs were estimated to be $81.9 million, including $11.9 million when 

natural gas savings are considered. Table 5-32 summarizes the nationwide costs for the two sub-options 

under Option 2a (annual Method 21 monitoring at the 10,000 ppm and 2,500 ppm repair thresholds). 

Applying the cost for the annual Method 21 monitoring and 500 ppm repair threshold to the 

estimated 16,562 oil production well sites and 5,518 natural gas production well sites in projected year 

2020, the total nationwide costs were estimated to be $132.3 million, which includes an estimated annual 

savings of $9.8 million when natural gas savings are considered. Likewise, for projected year 2025, for 

100,175 oil production well sites and 38,933 natural gas production well sites, the total nationwide cost 
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was estimated to be $830.5 million, including annual savings estimated around $64.9 million when natural 

gas savings are considered. For compressor stations, the nationwide costs for 2020 for this option were 

estimated to be $15 million, including $2.1 million when natural gas savings are considered. For 2025 for 

compressor stations the nationwide costs were estimated to be $90 million, including $12.4 million when 

natural gas savings are considered. Table 5-32 summarizes the nationwide costs for the two sub-options 

under Option 2a (annual Method 21 monitoring at the 10,000 ppm, 2,500 ppm and 500 ppm repair 

thresholds). 

Applying the cost for the semiannual Method 21 monitoring and 10,000 ppm repair threshold to 

the estimated 16,562 oil production well sites and 5,518 natural gas production well sites in projected year 

2020, the total nationwide costs were estimated to be $91.8 million, which includes an estimated annual 

savings of $7.2 million when natural gas savings are considered. Likewise, for projected year 2025, for 

100,175 oil production well sites and 38,933 natural gas production well sites, the total nationwide cost 

was estimated to be $575.8 million, including annual savings estimated around $47.7 million when natural 

gas savings are considered. For compressor stations, the nationwide costs for 2020 for this option were 

estimated to be $9.2 million, including $1.5 million when natural gas savings are considered. For 2025 for 

compressor stations the nationwide costs for 2020 were estimated to be $54.9 million, including $9.1 

million when natural gas savings are considered. 

Applying the cost for the semiannual Method 21 monitoring and 2,500 ppm repair threshold to the 

estimated 16,562 oil production well sites and 5,518 natural gas production well sites in projected year 

2020, the total nationwide costs were estimated to be $135.8 million, which includes an estimated annual 

savings of $9.2 million when natural gas savings are considered. Likewise, for projected year 2025, for 

100,175 oil production well sites and 38,933 natural gas production well sites, the total nationwide cost 

was estimated to be $852.3 million, including annual savings estimated around $60.9 million when natural 

gas savings are considered. For compressor stations, the nationwide costs for 2020 for this option were 

estimated to be $14 million, including $1.9 million when natural gas savings are considered. For 2025 for 

compressor stations the nationwide costs were estimated to be $83.8 million, including $11.6 million when 

natural gas savings are considered. 

Applying the cost for the semiannual Method 21 monitoring and 500 ppm repair threshold to the 

estimated 16,562 oil production well sites and 5,518 natural gas production well sites in projected year 

2020, the total nationwide costs were estimated to be $142.7 million, which includes an estimated annual 

savings of $9.7 million when natural gas savings are considered. Likewise, for projected year 2025, for 

100,175 oil production well sites and 38,933 natural gas production well sites, the total nationwide cost 
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was estimated to be $895.5 million, including annual savings estimated around $64.2 million when natural 

gas savings are considered. For compressor stations, the nationwide costs for 2020 for this option were 

estimated to be $15.3 million, including $2 million when natural gas savings are considered. For 2025 for 

compressor stations the nationwide costs were estimated to be $91.7 million, including $12.3 million when 

natural gas savings are considered. 

Table 5-33 summarizes the nationwide costs for the two Option 2b sub-options (semiannual 

Method 21 monitoring at the 10,000 ppm, 2,500 ppm, and 500 ppm repair thresholds). 
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Table 5-30. Nationwide Emission and Cost Analysis for Regulatory Option 1a – Annual OGI Moni

Fugitive Emission 

Component Location

Number of 

Sources 

Subject to 

NSPS 

Annual Cost Per 

Facility 

 ($)

Annual Cost 

Per Facility 

 ($) 

Nationwide Emission 

Reductions 

(tpy)

Total Nation

(million 

without savings with savings CH4 VOC without savings 

Projected Year 2020

Gas Well Site 5,518 $1,329 $908 10,019 2,785 $7.3 Oil Well Site 16,562 $1,329 $1,228 7,205 2,003 $22.0 Well Sites 22,080 NA NA 17,224 4,788 $29.3 Gathering & Boosting 259 $10,124 $6,865 3,641 1,012 $2.6 Transmission 6 $10,049 $10,049 150 4 $0.1 Storage 15 $13,634 $13,634 987 27 $0.2 Compressor Stations 280 NA NA 4,777 1,043 $2.9 

Projected Year 2025

Gas Well Site 38,933 $1,329 $908 70,691 19,650 $51.7 Oil Well Site 100,175 $1,329 $1,228 43,577 12,113 $133.1 Well Sites 139,108 NA NA 114,267 31,763 $184.9 Gathering & Boosting 1,554 $10,124 $6,865 21,845 6,072 $15.7 Transmission 36 $10,049 $10,049 898 25 $0.4 Storage 90 $13,634 $13,634 5,919 164 $1.2 Compressor Stations 1,680 NA NA 28,662 6,261 $17.3 
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Table 5-31. Nationwide Emission and Cost Analysis for Regulatory Option 1b – Semiannual OGI Mon

Fugitive Emission 

Component Location

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility 

 ($)

Annual Cost Per 

Facility 

 ($) 

Nationwide Emission 

Reductions 

(tpy)

Total 

(m

without savings with savings CH4 VOC withou

saving

Projected Year 2020

Gas Well Site 5,518 $2,230 $1,599 15,029 4,178 $12.3 Oil Well Site 16,562 $2,230 $2,079 10,807 3,004 $36.9 Well Sites 22,080 NA NA 25,835 7,182 $49.2 Gathering & Boosting 259 $15,881 $10,993 5,461 1,518 $4.1 Transmission 6 $15,732 $15,732 225 6 $0.1 Storage 15 $22,902 $22,902 1,480 41 $0.3 Compressor Stations 280 NA NA 7,165 1,565 $4.6 

Projected Year 2025

Gas Well Site 38,933 $2,230 $1,599 106,036 29,475 $86.8 Oil Well Site 100,175 $2,230 $2,079 65,365 18,170 $223.4 Well Sites 139,108 NA NA 171,401 47,645 $310.2 Gathering & Boosting 1,554 $15,881 $10,993 32,767 9,108 $24.7 Transmission 36 $15,732 $15,732 1,347 37 $0.6 Storage 90 $22,902 $22,902 8,879 246 $2.1 

Compressor Stations 1,680 NA NA 42,993 9,391 $27.3 
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Table 5-32. Nationwide Emission and Cost Analysis for Regulatory Option 2a – Annual Method 21 Mo

Fugitive Emission 

Component Location 

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility 

 ($)

Annual Cost Per 

Facility 

 ($) 

Nationwide Emission 

Reductions 

(tpy)

Total Nati

(millio

without savings with savings CH4 VOC without savings 

Projected Year 2020

10,000 ppm 

Gas Well Site 5,518 $4,020 $3,157 20,539 5,709 $22.2 Oil Well Site 16,562 $4,020 $3,813 14,769 4,106 $66.6 Well Sites 22,080 NA NA 35,308 9,815 $88.8 Gathering & Boosting 259 $37,203 $30,523 7,464 2,075 $9.6 Transmission 6 $37,203 $37,203 307 8 $0.2 Storage 15 $37,203 $37,203 2,022 56 $0.6 Compressor Stations 280 NA NA 9,793 2,139 $10.4 

2,500 ppm 

Gas Well Site 5,518 $6,103 $5,113 23,545 6,545 $33.7 Oil Well Site 16,562 $6,103 $5,866 16,931 4,706 $101.1 Well Sites 22,080 NA NA 40,475 11,251 $134.7 Gathering & Boosting 259 $55,860 $48,203 8,556 2,378 $14.5 Transmission 6 $55,860 $55,860 352 10 $0.3 Storage 15 $55,860 $55,860 2,318 64 $0.8 Compressor Stations 280 NA NA 11,226 2,452 $15.6 
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Fugitive Emission 

Component Location 

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility 

 ($)

Annual Cost Per 

Facility 

 ($) 

Nationwide Emission 

Reductions 

(tpy)

Total Nati

(millio

without savings with savings CH4 VOC without savings 

500 ppm 

Gas Well Site 5,518 $6,437 $5,406 24,547 6,823 $35.5 Oil Well Site 16,562 $6,437 $6,190 17,651 4,907 $106.6 Well Sites 22,080 NA NA 42,198 11,730 $142.1 Gathering & Boosting 259 $60,973 $52,990 8,920 2,480 $15.8 Transmission 6 $60,973 $60,973 367 10 $0.4 Storage 15 $60,973 $60,973 2,417 67 $0.9 Compressor Stations 280 NA NA 11,704 2,557 $17.1 

Projected Year 2025

10,000 ppm 

Gas Well Site 38,933 $4,020 $3,157 144,916 40,283 $156.5 Oil Well Site 100,175 $4,020 $3,813 89,332 24,832 $402.7 Well Sites 139,108 NA NA 234,248 65,115 $559.2 Gathering & Boosting 1,554 $37,203 $30,523 44,781 12,448 $57.8 Transmission 36 $37,203 $37,203 1,841 51 $1.3 Storage 90 $37,203 $37,203 12,134 336 $3.3 Compressor Stations 1680 NA NA 58,757 12,835 $62.5 

2,500 ppm 

Gas Well Site 38,933 $6,103 $5,113 163,123 46,178 $237.6 
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Fugitive Emission 

Component Location 

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility 

 ($)

Annual Cost Per 

Facility 

 ($) 

Nationwide Emission 

Reductions 

(tpy)

Total Nati

(millio

without savings with savings CH4 VOC without savings 

Oil Well Site 100,175 $6,103 $5,866 102,405 28,466 $611.3 Well Sites 139,108 NA NA 268,528 2,147 $848.9 Gathering & Boosting 1,554 $55,860 $48,203 51,335 14,270 $86.8 Transmission 36 $55,860 $55,860 2,111 58 $2.0 Storage 90 $55,860 $55,860 13,910 385 $5.0 Compressor Stations 1680 NA NA 67,355 14,713 $93.8 

500 ppm 

Gas Well Site 38,933 $6,437 $5,406 173,192 48,143 $250.6 Oil Well Site 100,175 $6,437 $6,190 106,763 29,677 $644.8 Well Sites 139,108 NA NA 279,954 77,820 $895.4 Gathering & Boosting 1,554 $60,973 $52,990 53,519 14,877 $94.8 Transmission 36 $60,973 $60,973 2,200 61 $2.2 Storage 90 $60,973 $60,973 14,502 401 $5.5 Compressor Stations 1680 NA NA 70,222 15,339 $102.4 
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Table 5-33. Nationwide Emission and Cost Analysis for Regulatory Option 2b – Semiannual Method 21 M

Fugitive Emission 

Component Location 

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility 

 ($)

Annual Cost Per 

Facility 

 ($) 

Nationwide Emission 

Reductions 

(tpy)

Total 

(m

without savings with savings CH4 VOC withou

saving

Projected Year 2020

10,000 ppm 

Gas Well Site 5,518 $4,482 $3,725 18,034 5,013 $24.7 Oil Well Site 16,562 $4,482 $4,301 12,968 3,605 $74.2 Well Sites 22,080 NA NA 31,002 8,618 $99.0 Gathering & Boosting 259 $38,128 $32,263 6,553 1,822 $9.9 Transmission 6 $38,128 $38,128 269 7 $0.2 Storage 15 $38,128 $38,128 1,776 49 $0.6 Compressor Stations 280 NA NA 8,599 1,878 $10.7 

2,500 ppm 

Gas Well Site 5,518 $6,565 $5,597 23,044 6,406 $36.2 Oil Well Site 16,562 $6,565 $6,333 16,570 4,606 $108.7 Well Sites 22,080 NA NA 39,614 11,012 $145.0 Gathering & Boosting 259 $56,785 $49,291 8,374 2,328 $14.7 Transmission 6 $56,785 $56,785 344 10 $0.3 Storage 15 $56,785 $56,785 2,269 63 $0.9 Compressor Stations 280 NA NA 10,987 2,400 $15.9 
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Fugitive Emission 

Component Location 

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility 

 ($)

Annual Cost Per 

Facility 

 ($) 

Nationwide Emission 

Reductions 

(tpy)

Total 

(m

without savings with savings CH4 VOC withou

saving

500 ppm 

Gas Well Site 5,518 $6,899 $5,879 24,296 6,754 $38.1 Oil Well Site 16,562 $6,899 $6,655 17,471 4,857 $114.3 Well Sites 22,080 NA NA 41,767 11,610 $152.3 Gathering & Boosting 259 $61,898 $53,996 8,829 2,454 $16.0 Transmission 6 $61,898 $61,898 363 10 $0.4 Storage 15 $61,898 $61,898 2,392 66 $0.9 Compressor Stations 280 NA NA 11,584 2,530 $17.3 

Projected Year 2025

10,000 ppm 

Gas Well Site 38,933 $4,482 $3,725 127,243 35,370 $174.5 Oil Well Site 100,175 $4,482 $4,301 78,438 21,804 $449.0 Well Sites 139,108 NA NA 205,681 57,174 $623.5 Gathering & Boosting 1,554 $38,128 $32,263 39,320 10,930 $59.3 Transmission 36 $38,128 $38,128 1,617 45 $1.4 Storage 90 $38,128 $38,128 10,654 295 $3.4 Compressor Stations 1680 NA NA 51,591 11,270 $64.1 

2,500 ppm 

Gas Well Site 38,933 $6,565 $5,597 162,588 45,195 $255.6 
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Fugitive Emission 

Component Location 

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility 

 ($)

Annual Cost Per 

Facility 

 ($) 

Nationwide Emission 

Reductions 

(tpy)

Total 

(m

without savings with savings CH4 VOC withou

saving

Oil Well Site 100,175 $6,565 $6,333 100,226 27,860 $657.6 Well Sites 139,108 NA NA 262,814 73,056 $913.2 Gathering & Boosting 1,554 $56,785 $49,291 50,243 13,966 $88.2 Transmission 36 $56,785 $56,785 2,066 57 $2.0 Storage 90 $56,785 $56,785 13,614 377 $5.1 Compressor Stations 1680 NA NA 65,922 14,400 $95.4 

500 ppm 

Gas Well Site 38,933 $6,899 $5,879 171,424 47,652 $268.6 Oil Well Site 100,175 $6,899 $6,655 105,673 29,375 $691.2 Well Sites 139,108 NA NA 277,098 77,026 $959.8 Gathering & Boosting 1,554 $61,898 $53,996 52,973 14,725 $96.2 Transmission 36 $61,898 $61,898 2,178 60 $2.2 Storage 90 $61,898 $61,898 14,354 397 $5.6 Compressor Stations 1680 NA NA 69,505 15,183 $104.0 
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5.5.2.3 Nationwide Impacts Excluding Low Producing Natural Gas and Oil Wells 

We also evaluated an alternative nationwide impact scenario that accounts for well sites that 

produce relatively little crude oil and/or natural gas. Under this scenario, low producing wells would not 

be subject to fugitive emissions monitoring provisions. While there are several criteria for defining a lowproducing well, we believe the definition of a "stripper well" in Internal Revenue Services (IRS) 

regulations, is consistent with the type of well which would be considered low-producing under this 

scenario. Under the IRS regulations, a stripper well property “means, with respect to any calendar year, 

any property with respect to which the amount determined by dividing—(i) the average daily production 

of domestic crude oil and domestic natural gas from producing wells on such property for such calendar 

year, by (ii) the number of such wells, is 15 barrel equivalents or less". 59 

 From the 2012 natural gas and oil well completion data derived from HPDI as described in section 

5.3.2 above, we determined the percentage of wells that meet the above definition and deducted that 

number of wells from the nationwide population. To determine the barrel equivalents for the HPDI natural 

gas production data, we converted the first month of natural gas production data for each well using 0.178 

barrel equivalents per Mcf of natural gas produced. If the well also produced oil, the number of barrels of 

oil produced was added to the barrel equivalents calculated for the natural gas. Based on this definition, of 

the 35,454 oil well completions in 2012, 15,354 of the oil wells (or 43 percent) met the definition of a lowproducing well. Of the 8,459 natural gas completions in 2012, 2,567 (or 30 percent) natural gas wells met 

the definition of a low-producing well. For our analysis, we assume that the percentages of low-producing 

wells in the overall number of completions in 2012 would also apply to the overall number of well sites. 

Using the estimated percentage of low-producing wells, we reduced the number of well sites in the 2020 

and 2025 activity counts to represent the estimated population of well sites that would be covered by the 

NSPS fugitive emissions requirements taking into account that wells producing no more than 15 barrel 

equivalents of oil per day would not be subject to the requirements. 

 Based on those percentages, we estimated 3,863 natural gas well sites and 9,440 oil well sites will 

be subject to the fugitive emissions monitoring requirements in 2020 and 27,2533 natural gas well sites 

and 57,100 oil wells sites will be subject by 2025. Tables 5-34 through 5-37 summarize the estimated 

nationwide cost impacts for this alternative population of well sites for each of the regulatory options 

discussed above.

                                                            

59 26 U.S.C. 613A(c)(6)(E).
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Table 5-34. Nationwide Emission and Cost Analysis for Regulatory Option 1a (Excluding Low-Prod

– Annual OGI Monition and Repair

Fugitive Emission 

Component Location

Number of 

Sources 

Subject to 

NSPS 

Annual Cost Per 

Facility ($)

Annual Cost 

Per Facility ($)

Nationwide Emission 

Reductions (tpy)

Total Nation

(million 

without savings with savings CH4 VOC without savings 

Projected Year 2020

Gas Well Site 3,863 $1,329 $908 7,014 1,950 $5.1 Oil Well Site 9,440 $1,329 $1,228 4,106 1,141 $12.5 Well Sites 13,303 NA NA 11,120 3,091 $17.7 

Projected Year 2025

Gas Well Site 27,253 $1,329 $908 49,483 13,755 $36.2 Oil Well Site 57,100 $1,329 $1,228 24,839 6,905 $75.9 Well Sites 84,353 NA NA 74,322 20,660 $112.1 
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Table 5-35. Nationwide Emission and Cost Analysis for Regulatory Option 1b (Excluding Low-Prod

– Semiannual OGI Monition and Repair 

Fugitive Emission 

Component Location

Number of 

Sources 

Subject to 

NSPS 

Annual Cost Per 

Facility ($)

Annual Cost Per 

Facility ($) 

Nationwide Emission 

Reductions (tpy)

Total Nation

(million 

without savings with savings CH4 VOC without savings 

Projected Year 2020

Gas Well Site 3,862 $2,230 $1,599 10,518 2,924 $8.6 Oil Well Site 9,440 $2,230 $2,079 6,160 1,712 $21.0 Well Sites 13,302 NA NA 16,678 4,636 $29.7 

Projected Year 2025

Gas Well Site 27,253 $2,230 $1,599 74,225 20,633 $60.8 Oil Well Site 57,100 $2,230 $2,079 37,258 10,357 $127.3 Well Sites 84,353 NA NA 111,483 30,989 $188.1 
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Table 5-36. Nationwide Emission and Cost Analysis for Regulatory Option 2a (Excluding Low-Prod

– Annual Method 21 Monitoring and Repair 

Fugitive Emission 

Component Location 

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility ($)

Annual Cost Per 

Facility ($) 

Nationwide Emission 

Reductions (tpy)

Total Nati

(millio

without savings with savings CH4 VOC without savings 

Projected Year 2020

10,000 ppm 

Gas Well Site 3,863 $4,020 $3,157 14,379 3,997 $15.5 Oil Well Site 9,440 $4,020 $3,813 8,418 2,340 $37.9 Well Sites 13,303 NA NA 22,797 6,337 $53.5 

2,500 ppm 

Gas Well Site 3,863 $6,103 $5,113 16,483 1,212 $23.6 Oil Well Site 9,440 $6,103 $5,866 9,650 236 $57.6 Well Sites 13,303 NA NA 26,133 1,449 $81.2 

500 ppm 

Gas Well Site 3,863 $6,437 $5,406 17,184 4,777 $24.9 Oil Well Site 9,440 $6,437 $6,190 10,061 2,797 $60.8 Well Sites 13,303 NA NA 27,245 7,573 $85.6 

Projected Year 2025

10,000 ppm 

Gas Well Site 27,253 $4,020 $3,157 101,441 28,198 $109.6 Oil Well Site 57,100 $4,020 $3,813 50,920 14,154 $229.5 Well Sites 84,353 NA NA 152,360 42,352 $339.1 
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Fugitive Emission 

Component Location 

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility ($)

Annual Cost Per 

Facility ($) 

Nationwide Emission 

Reductions (tpy)

Total Nati

(millio

without savings with savings CH4 VOC without savings 

2,500 ppm 

Gas Well Site 27,253 $6,103 $5,113 116,285 1,229 $166.3 Oil Well Site 57,100 $6,103 $5,866 58,371 236 $348.5 Well Sites 84,353 NA NA 174,657 1,466 $514.8 

500 ppm 

Gas Well Site 27,253 $6,437 $5,406 121,234 33,700 $175.4 Oil Well Site 57,100 $6,437 $6,190 60,855 16,916 $367.6 Well Sites 84,353 NA NA 182,089 50,616 $543.0 
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Table 5-3737. Nationwide Emission and Cost Analysis for Regulatory Option 2b (Excluding Low-Pro

– Semiannual Method 21 Monitoring and Repair 

Fugitive Emission 

Component Location 

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility ($)

Annual Cost Per 

Facility ($) 

Nationwide Emission 

Reductions (tpy)

Total Nati

(millio

without savings with savings CH4 VOC without savings 

Projected Year 2020

10,000 ppm 

Gas Well Site 3,863 $4,482 $3,725 12,622 3,509 $17.3 Oil Well Site 9,440 $4,482 $4,301 7,392 2,055 $42.3 Well Sites 13,302 NA NA 20,014 5,563 $59.6 

2,500 ppm 

Gas Well Site 3,863 $6,565 $5,597 16,128 1,186 $25.4 Oil Well Site 9,440 $6,565 $6,333 9,445 231 $62.0 Well Sites 13,302 NA NA 25,573 1,418 $87.3 

500 ppm 

Gas Well Site 3,863 $6,899 $5,879 17,009 4,728 $26.7 Oil Well Site 9,440 $6,899 $6,655 9,958 2,768 $65.1 Well Sites 13,303 NA NA 26,967 7,496 $91.8 

Projected Year 2025

10,000 ppm 

Gas Well Site 27,253 $4,482 $3,725 89,070 24,759 $122.2 Oil Well Site 57,100 $4,482 $4,301 44,710 12,428 $255.9 Well Sites 84,353 NA NA 133,780 37,187 $378.1 
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Fugitive Emission 

Component Location 

Number of 

Sources 

Subject to 

NSPS 

Annual Cost 

Per Facility ($)

Annual Cost Per 

Facility ($) 

Nationwide Emission 

Reductions (tpy)

Total Nati

(millio

without savings with savings CH4 VOC without savings 

2,500 ppm 

Gas Well Site 27,253 $6,565 $5,597 113,811 1,203 $178.9 Oil Well Site 57,100 $6,565 $6,333 57,129 231 $374.9 Well Sites 84,353 NA NA 170,941 1,435 $553.8 

500 ppm 

Gas Well Site 27,253 $6,899 $5,879 119,997 33,356 $188.0 Oil Well Site 57,100 $6,899 $6,655 60,234 16,744 $394.0 Well Sites 84,353 NA NA 180,231 50,100 $582.0 
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6.0 PNEUMATIC CONTROLLERS 

The 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 used throughout the oil and natural gas sector as 

part of the instrumentation to control the position of valves. This chapter describes pneumatic controllers 

in the transmission and storage segment, including their function and associated emissions. Standards are 

already in place for pneumatic controllers in the production and processing segment; therefore they are 

not discussed here. Options available to reduce emissions from pneumatic controllers in the transmission 

and storage segment are presented, along with costs, emission reductions, and secondary impacts. Finally, 

this chapter discusses considerations in developing regulatory alternatives for pneumatic controllers. 

6.1 Process Description 

6.1.1 Pneumatic Controllers 

For the purpose of this document, a pneumatic controller is a device that uses natural gas to 

transmit a process signal or condition pneumatically and that may also adjust a valve position based on 

that signal, with the same bleed gas and/or a supplemental supply of power gas. In the vast majority of 

applications, the natural gas industry uses pneumatic controllers that make use of readily available highpressure natural gas to provide the required energy and control signals. In the transmission and storage 

segment, an estimated 84,000 pneumatic controllers actuate isolation valves and regulate gas flow and 

pressure at compressor stations, pipelines, and storage facilities.60

Pneumatic controllers are automated instruments used for maintaining a process condition such as 

liquid level, pressure, pressure differential, and temperature. In many situations across all segments of the 

oil and natural gas industry, pneumatic controllers make use of the available high-pressure natural gas to 

operate or control a valve. In these “gas-driven” pneumatic controllers, natural gas may be released with 

every valve movement and/or 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. There are three basic designs: (1) continuous bleed devices are used to modulate flow, 

                                                            

60 U.S. EPA. Lessons Learned: Options for Reducing Methane Emissions From Pneumatic Devices in the Natural Gas Industry. 

OAR: Natural Gas Star. Washington, DC. February 2004. 
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liquid level, or pressure, and gas is vented continuously at a rate that may vary over time; (2) intermittent 

controllers release gas only when they open or close a valve or as they throttle the gas flow; and (3) selfcontained devices release gas to a downstream pipeline instead of to the atmosphere. This analysis 

assumes self-contained devices that release natural gas to a downstream pipeline instead of to the 

atmosphere have no emissions. Furthermore, it is recognized that “closed loop” systems are applicable 

only in instances with very low pressure61 and may not be suitable to replace many applications of 

bleeding pneumatic devices. Therefore, these devices are not further discussed in this analysis. 

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. Therefore, because intermittent controllers are inherently low emitting sources and the total 

emissions are dependent on the applications in which they are used, we did not include intermittent 

controllers in this analysis. This is consistent with the treatment of these controllers under the 2012 

NSPS. 

In addition, not all pneumatic controllers are gas driven. At sites with electrical service sufficient 

to power an instrument air compressor, mechanical or solar-powered, electrically powered pneumatic 

devices can be used. These “non-gas driven” pneumatic controllers can be mechanically operated or use 

sources of power other than pressurized natural gas, such as compressed “instrument air.” Because these 

devices are not gas driven, they do not directly release natural gas. 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. Instrument air systems are feasible only at 

oil and natural gas locations where the devices can be driven by compressed instrument air systems and 

have electrical service sufficient to power an air compressor. This analysis assumes that natural gas 

                                                            

61 Memorandum to Bruce Moore, U.S. EPA from Denise Grubert, EC/R. Meeting Minutes from EPA Meeting with the API. 

October 2011. 
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processing plants are the only facilities in the oil and natural gas source category likely to have electrical 

service sufficient to power an instrument air system, and that most existing gas processing plants use 

instrument air instead of gas driven devices.62

6.2 Emissions Data and Information 

6.2.1 Summary of Major Studies and Emission 

In the evaluation of the emissions from pneumatic controllers in the transmission and storage 

segment and the potential options available to reduce the emissions, numerous studies and sources of 

information were consulted. Table 6-1 presents these studies and sources of information with an indication 

of the type of relevant information contained in each resource. 

Table 6-1. Major Studies and Sources of Information Reviewed for Emissions and Activity Data 

Report Name Affiliation

Year of 

Report

Number of 

Devices

Emissions 

Information

Control 

Information

GHG Mandatory Reporting 

Rule and Technical 

Supporting Documenta

 

EPA 2013 Nationwide X 

Inventory of GHG Emissions and 

Sinks: 1990-2012b EPA 2014 Nationwide/ 

Regional X 

CH4 Emissions from the 

Natural Gas Industryc GRI/EPA 1996 Nationwide X 

CH4Emissions from the 

Petroleum Industry (draft)d EPA 1996 Nationwide X 

CH4 Emissions from the 

Petroleum Industrye

 EPA 1999 Nationwide X 

Oil and Gas Emission 

Inventories for Western Statesf 

Western 

Regional Air 

Partnership 

2005 Regional X 

Natural Gas STAR Programg EPA 2000- 

2010 X X 

Measurements of CH4 Emissions 

from Natural Gas Production Sites 

in the U.S.h

Multiple 

Affiliations, 

Academic and 

Private 

2013 Nationwide X 

Determining Bleed Rates for 

Pneumatic Devices in British 

Columbiai 

 

The Prasino Group 2013 British 

Columbia X 

                                                            

62 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic Devices. Prepared for the 

GRI and EPA. EPA-600/R-96-080k. June 1996.
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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 CH4

Emission Reduction Opportunities 

in the U.S. Onshore Oil and 

Natural Gas Industriesk

ICF International 2014 Nationwide X X 

a. U.S. EPA. GHG Emissions Reporting From the Petroleum and Natural Gas Industry: Background TSD. Climate Change 

Division. Washington, DC. November 2010. 

b U.S. EPA. Methodology for Estimating CH4 and CO2 Emissions from Natural Gas Systems. GHG Inventory: Emission and 

Sinks 1990-2008. Washington, DC. and U.S EPA. Methodology for Estimating CH4 and CO2 Emissions from Petroleum 

Systems. GHG Inventory: Emission and Sinks 1990-2008. Washington, DC. 

c. Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical Report. Prepared for the 

GRI and EPA. EPA-600/R-96-080b. June 1996, Radian International LLC. Methane Emissions from the Natural Gas Industry, 

Vol. 3: General Methodology. Prepared for the GRI and EPA. EPA-600/R-96-080c. June 1996, Radian International LLC. 

Methane Emissions from the Natural Gas Industry, Vol. 5: Activity Factors. Prepared for the GRI and EPA. EPA-600/R-96-

080e. June 1996, and Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic 

Devices. Prepared for the GRI and EPA. EPA-600/R-96-080k. June 1996. 

d. Radian International LLC, Methane Emissions from the U.S. Petroleum Industry, draft report for the U.S. EPA, June 14, 

1996. 

e. ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry. Prepared for the U.S. EPA. 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. EPA. Lessons Learned: Options for Reducing Methane Emissions From Pneumatic Devices in the Natural Gas 

Industry. OAR: Natural Gas Star. Washington, DC. February 2004. 

h. Memorandum to Bruce Moore from Heather Brown. Gas Composition Methodology. July 2011. 

i. U.S. EPA. Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air. OAR: Natural Gas Star. Washington, DC. 

February 2004. 

j. U.S. EPA. PRO Fact Sheet No. 301. Convert Pneumatics to Mechanical Controls. OAR: 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 Representative Pneumatic Device Emissions 

Continuous bleed pneumatic controllers can be classified into two types based on their emissions 

rates: (1) high-bleed controllers and (2) low-bleed controllers. A controller is considered to be highbleed when the continuous bleed emissions are in excess of 6 standard cubic feet per hour (scfh), while 

low-bleed devices bleed at a rate less than or equal to 6 scfh.63

For this analysis, the EPA consulted information in the appendices of the Natural Gas STAR 

Lessons Learned document on pneumatic devices, Subpart W of the GHG Reporting rule64, the Inventory 

of GHG Emissions and Sinks, new studies, as well as pneumatic controller vendor information obtained 

                                                            

63 The classification of high-bleed and low-bleed devices originated from a report by Pacific Gas & Electric (PG&E) and the

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 “highbleed” types (PG&E 1990).” This range of bleed rates is equivalent to 6 to 30 cubic feet per hour. 64 Available at http://www.epa.gov/ghgreporting/reporters/subpart/w.html. 
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during the development of the NSPS rulemaking. The data obtained from vendors included emission 

rates, costs, and any other pertinent information for each pneumatic device model (or model family). All 

pneumatic devices 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. Since publication of the white paper, additional 

data have become available on emissions from pneumatic controllers, including reporting year 2013 data 

from GHGRP, and new measurement data from Subramanian et al. 2015, and Allen et al. 2014. GHGRP 

reported methane emissions for 2013 are 190,008 tons CO2e in transmission, and 111,555 tons CO2e in 

storage. In the Subramanian et al. 2015 data set, the average emission rate for pneumatic controllers in 

the transmission segment was 12.9 scfh, and the average emission rate for pneumatic controllers in the 

storage segment was 21.2 scfh. Information was not available on the fraction of high bleed versus low 

and intermittent bleed controllers in each population. 

Although by definition, a low-bleed device can emit up to 6 scfh, through this vendor research, it 

was determined that the 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 

emissions 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.65,66 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; which is an important factor in developing a 

representative emission factor. For this analysis, the EPA determined that best available emissions rate 

estimates for pneumatic controllers are presented in Table W-1A of the GHG Mandatory Reporting Rule 

for the Oil and Natural Gas Industry (Subpart W). 

The basic approach used for this analysis of emissions from pneumatic controllers was to first 

approximate the natural gas emissions from the average pneumatic controller type in the transmission and 

storage segment then estimate CH4 and VOC using a representative gas composition.67 

The specific ratios from the representative gas composition were 0.908 lbs of CH4 per pound of 

natural gas and 0.0277 lbs VOC per pound CH4. Table 6-2 summarizes the estimated bleed emissions for 

a representative pneumatic controller by industry segment and device type.

                                                            

65 U.S. EPA. GHG Emissions Reporting From the Petroleum and Natural Gas Industry: Background TSD. Climate Change 

Division. Washington, DC. November 2010. 

66 All rates are listed at an assumed supply gas pressure of 20 psig. 

67 See footnote 45. 
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Table 6-2. Average Bleed Emission Estimates per Pneumatic Controller in the Natural Gas 

Transmission and Storage Segmenta, b

High-Bleed 

(tpy) 

Low-Bleed 

(tpy) 

CH4 VOC CH4 VOC 

3.013 0.083 0.227 0.00628 

a. The conversion factor used in this analysis is 1,000 cubic feet (Mcf) of CH4 is equal to 0.0208 tons CH4. 

b. Natural gas transmission and storage emission factors for continuous bleed controllers were derived from Table W-1A of 

Subpart W.

6.3 Nationwide Emissions from New Sources 

6.3.1 Approach 

Nationwide emissions from newly installed natural gas pneumatic devices for a typical year were 

calculated by estimating the number of pneumatic devices installed in a typical year and multiplying by 

the estimated annual emissions per device listed in Table 6-2. The number of new pneumatic devices 

installed for a typical year was determined using the methodologies described in section 6.3.2 of this 

chapter. 

6.3.2 Population of Controllers Installed Annually 

The number of pneumatic controllers installed in the transmission and storage segment was 

approximated using the Inventory of U.S. GHG Emissions and Sinks: 1990-2012. The number of new 

devices installed in a given year was estimated by subtracting the prior year (e.g., 2011) from the given 

years total (e.g., 2012). This difference was assumed to be the number of new devices installed in the 

latter year (e.g., Number of new devices installed during 2012 equals Pneumatics in 2012 minus 

Pneumatics in 2011). A 10-year average was calculated based on the number of new controllers installed 

in 2003 through 2012 in order to determine the average number of new devices installed in a typical 

year. An average was taken of only the years with an increase in pneumatic controllers. 

The number of facilities estimated in absence of regulation was undeterminable due to the 

magnitude of new sources estimated and the lack of sufficient data that could indicate the number of 

controllers that would be installed in states that may have regulations requiring low bleed controllers, such 

as in Wyoming and Colorado. 

Once the population counts for the number of pneumatics in each segment were established, this 

population count was further refined to account for the number of intermittent controllers that would be 

installed versus a bleed controller. This estimate of the percent of intermittent and bleed controllers was 

based on raw data from the GRI study, where 32 percent of the pneumatic controllers are bleed devices 
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in the production segment, and 32 percent of the pneumatic controllers are bleed devices in the 

transmission and storage segment.68 The distinction between the number of high-bleed and low-bleed 

devices was not estimated because this analysis assumes it is not possible to predict or ensure where low 

bleeds will be used in the future. Table 6-3 summarizes the estimated number of new devices installed 

per year. 

Table 6-3. Estimated Number of Pneumatic Controllers Installed in a Typical Year in the Natural 

Gas Transmission and Storage Segment 

Number of New Controllers Estimated for a Typical Yeara, b

Intermittent Bleed-Devices Total

558 262 820 

a. National averages of population counts from the Inventory were refined to include the difference in intermittent and 

bleed devices based on raw data found in the GRI/EPA study. This is based on the assumption that 32 percent of the 

pneumatic controllers are bleed devices in the transmission and storage segment. 

b. The number of pneumatics controllers estimated for the transmission and storage segment was approximated from 

comparing a 10 year average of new controllers installed in 2003 through 2012 in order to establish an average number 

of pneumatics being installed in this industry segment in a typical year. This analysis was performed using the 

Inventory of U.S. GHG Emissions and Sinks: 1990-2012.

6.3.3 Emission Estimates 

Nationwide baseline emission estimates for pneumatic devices for new sources in a typical year 

are summarized in Table 6-4. This analysis assumed for the nationwide emission estimate that all bleeddevices have the high-bleed emission rates estimated in Table W-3 of the GHG Reporting Rule, Subpart 

W since it cannot be predicted which sources would install a low bleed versus a high bleed controller. 

Table 6-4. Nationwide Baseline Emissions from Representative Pneumatic Controller Installed in a 

Typical Year in Natural Gas Transmission and Storage Segmenta, b

Baseline Emissions from 

Representative New Continuous 

Bleed Controller 

(tpy) 

Number of New Continuous Bleed 

Controllers 

Expected Per Year 

Nationwide Baseline Emissions 

from New Continuous Bleed 

Controller 

(tpy) 

CH4 VOC CH4 VOC 

3.013 0.083 262 790.5 21.9 

a. Baseline emissions were based on the bleed rates for a high-bleed controllers. 

b. To estimate VOC emissions, the weight ratio of 0.0277 lbs VOC per pound CH4 was used. 

6.4 Control Techniques 

Several options to reduce emissions have been developed over the years to reduce emissions from 

pneumatic controllers. Table 6-5 provides a summary of these options for reducing emissions from 

pneumatic controllers including: instrument air, non-gas driven controls, and enhanced maintenance. The 

                                                            

68 See footnote 51. 
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use of instrument air systems, as discussed in the 2012 NSPS TSD69, requires a constant source of 

electric power. Because electric power is not necessarily available at all transmission and storage 

affected facilities, the use of instrument air systems would not be practically feasible as a control for 

emissions from pneumatic controllers in this industry segment. Likewise, because the mechanical 

systems identified for use in this industry would require, at minimum, a backup source of electric power, 

this option is also not considered to be practically feasible for use in controlling these pneumatic 

controller emissions. The enhanced maintenance option would be considered to be too variable and 

costly as a viable option for control pneumatic controller emissions. Based on these concerns, further 

analyses of these options were not conducted 

Given the various applicability, cost of emissions reductions and cost issues with the control 

options, the replacement of a high-bleed with a low-bleed device is the most likely scenario for reducing 

emissions from pneumatic controllers. This conclusion is consistent with and supported by requirements 

of States such as Colorado and Wyoming that require the use of low-bleed controllers in place of highbleed controllers. Therefore, low-bleed controllers are further described in the following section, along 

with estimates of the impacts of their application for a representative device and nationwide basis. 

As noted above, intermittent controllers are assumed to have zero bleed emissions. In addition, 

these controllers are assumed to not always be used in the same functional application as continuous 

bleed controllers. Therefore, intermittent controllers are not an appropriate option for control for all 

continuous bleed controllers. It is assumed intermittent, or no-bleed, controllers meet the definition of a 

low-bleed. 

                                                            

69 See footnote 4. 
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Table 6-5. Alternative Control Options for Pneumatic Controllers 

Option Description Applicability/Effectiveness 

Install Low Bleed Device in Place of High Bleed Device 

Low-bleed devices provide the same functional control as a high-bleed device, while emitting less continuous bleed emissions. 

Applicability may depend on the function of instrumentation for an individual devicon whether the device is a level, pressureor temperature controller. 

Convert to Instrument Aira

Compressed air may be substituted for natural gas in pneumatic systems without altering any of the parts of the pneumatic control. In this type of system, atmospheric air is compressed, stored in a tank, filtered and then dried for instrument use. For utility purposes such as small pneumatic pumps, gas compressor motor starters, pneumatic tools and sand blasting, air would not need to be dried. Instrument air conversion requires additional equipment to properly compress and control 

the pressured air. This equipment includes a compressor, power source, air dehydrator and air storage vessel. 

Replacing natural gas with instrument air pneumatic controls eliminates VOC emisfrom bleeding pneumatics. These systems achieve 100 percent reduction in emissionis most effective at facilities where there high concentration of pneumatic control valves and an operator present. Since the systems are powered by electric compresthey require a constant source of electricapower or a back- up natural gas pneumatidevice. 

Mechanical and Solar Powered Systems in place of Bleed Deviceb

Mechanical controls operate using a simple design comprised of levers, hand wheels, springs and flow channels. The most common mechanical control device is the liquid-level float to the drain valve position with mechanical linkages. Electricity or small electrical motors (including solar powered) have been used to operate valves. Solar control systems are driven by solar power cells that actuate mechanical devices using electric power. As such, solar cells require some type of back-up power or storage to ensure reliability. 

Application of mechanical controls is limited because the control must be locatein close proximity to the process measurement. Mechanical systems are alsincapable of handling larger flow fluctuations. Electric powered valves are only reliable with a constant supply of electricity. Overall, these options are applicable in niche areas but can achieve 100 percent reduction in emissions where applicable. 
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Option Description Applicability/Effectiveness 

Enhanced Maintenancec

Instrumentation in poor condition typically bleeds 5 to 10 scf per hour more than representative conditions due to worn seals, gaskets, diaphragms; nozzle corrosion or wear, or lose control tube fittings. This may not impact the operations but does increase emissions. 

Enhanced maintenance to repair and maintain pneumatic devices periodically reduce emissions. Proper methods of maintaining a device are highly variable acould incur significant costs. 

a. U.S. EPA. Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air. OAR: Natural Gas Star. Washington, DC. February 

b. U.S. EPA. PRO Fact Sheet No. 301. Convert Pneumatics to Mechanical Controls. OAR: Natural Gas Star. Washington, DC. Septemc. CETAC-WEST. Fuel Gas Best Management Practices: Efficient Use of Fuel Gas in Pneumatic Instruments. Prepared for the Canadia

Producers. May 2008. 
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6.4.1 Low-Bleed Controller Emission Reduction Potential 

As discussed in the above sections, low-bleed controllers provide the same operational function 

as high-bleed controllers, but have lower continuous bleed emissions. As summarized in Table 6-6, the 

average achievable reduction in emissions per controller is estimated to be approximately 2.79 tons of 

CH4 and 0.077 tons of VOC. As noted in section 6.2, a low-bleed controller can emit up to 6 scfh, which 

is higher than the expected emissions from the typical low-bleed device currently available on the 

market. 

Table 6-6. Estimated Annual Bleed Emission Reductions from Replacing a Representative HighBleed Pneumatic Controller with a Representative Low-Bleed Pneumatic Controller in the Natural 

Gas Transmission and Storage Segment 

Baseline Emissions Reductions - High-Bleed Replaced with Low-Bleeda

(tpy) 

CH4 VOC 

2.79 0.077 

a. Average emission reductions based on the typical emission rate from high-bleed and low-bleed controllers as 

listed in Table 6-2. 

6.4.2 Emission Reduction Potential 

There are certain situations in which replacing and retrofitting 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, it is 

assumed about 80 percent of high-bleed devices can be replaced with low-bleed devices throughout the 

transmission and storage segment.70 This corresponds to 210 new high-bleed devices in the production 

segment (out of 262) that can be replaced with a new low-bleed alternative. 

Applicability may depend on the function of instrumentation for an individual device such as 

whether the device is a level, pressure, or temperature controller. High-bleed pneumatic devices may not 

be applicable for replacement with low-bleed devices because a process condition may require a fast or 

precise control response so that it does not stray too far from the desired set point. A slower-acting 

controller could potentially result in damage to equipment and/or become a safety issue. An example of 

this is on a compressor where pneumatic devices may monitor the suction and discharge pressure and 

actuate a re-cycle when one or the other is out of the specified target range. Other scenarios for fast and 

precise control include transient (non-steady) situations where a gas flow rate may fluctuate widely or 

                                                            

70 See footnote 49. 
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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 accommodate control from a low-bleed 

device, which is slower-acting and less precise. 

6.4.3 Cost Impacts 

As described in Section 6.2.2, costs were based on the 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 devices.71 As Table 6-7 indicates, the average cost for a low bleed pneumatic is 

$2,471, while the average cost for a high bleed is $2,698.72 Thus, the incremental cost of installing a lowbleed device instead of a high-bleed device is on the order of $227 per device. In order to analyze cost 

impacts, the incremental cost to install a low-bleed instead of a high-bleed was annualized for a 15-year 

period using a 7 percent interest rate. This equated to an annualized cost of around $25 per low-bleed 

controller. 

Table 6-7. Cost Projections for Representative Pneumatic Controllers (2012)a

Controller Type Minimum Cost 

($) 

Maximum Cost

($) 

Average Cost 

($) 

Low-Bleed 

Incremental Cost 

($) 

High-Bleed Controller $387 $7,398 $2,471 

$227 

Low-Bleed Controller $554 $9,356 $2,698 

a. Cost data from the 2012 NSPS was converted to 2012 dollars using the Federal Reserve Economic Data GDP Price Deflator. 

During the development of the 2012 NSPS major pneumatic controller vendors were surveyed for costs, emission rates, and 

any other pertinent information that would give an accurate picture of the present industry.

Although monetary savings associated with additional gas captured to the sales line exists, these 

savings were not estimated for the transmission and storage segment because it is assumed the owner of 

the pneumatic controller generally is not the owner of the natural gas. The cost per ton of emissions 

reduced was then calculated in two ways. The first method allocated all of the costs to each pollutant 

separately. The second method prorated costs among the pollutants that a given technology reduced (i.e., 

CH4 and VOC). This proration was based on estimates of the percentage reduction expected for each 

pollutant. Table 6-8 provides a summary of low-bleed pneumatic cost of control. 

                                                            

71 Ibid. 

72 Costs are estimated in 2012 U.S. Dollars.
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Table 6-8. Cost-of Control for Low-Bleed Pneumatic Controllers versus High Bleed Pneumatics for 

the Transmission and Storage Segment (2012) 

Method 

Incremental Capital 

Cost Per Unita

($)

Total Annual 

Cost Per Unitb

($/year)

Emissions Reductions 

(tpy) 

Cost of Control 

($/ton) 

CH4 VOC CH4 VOC 

Standard 100% $227 $24.95 2.79 0.077 $9 $323 

Prorated 50/50 $227 $24.95 2.79 0.077 $4 $162 

 a. Incremental cost of a low bleed controller versus a high bleed controller as summarized in Table 6-7. 

 b. Annualized cost assumes a 7 percent interest rate over a 15-year equipment lifetime. 

6.4.4 Secondary Impacts 

Low-bleed pneumatic controllers are a replacement option for high-bleed devices that simply 

bleed less natural gas that would otherwise be emitted in the actuation of pneumatic valves. No wastes 

would be created, no wastewater generated, and no electricity required. Therefore, there are no secondary 

impacts expected from the use of low-bleed pneumatic devices. 

6.5 Regulatory Options 

The affected facility definition for pneumatic controller is defined as a single natural gas 

pneumatic controller. Therefore, pneumatic controllers would be subject to a New Source Performance 

Standard (NSPS) at the time of installation. The following Regulatory alternatives were evaluated: 

 Regulatory Option 1. Establish an emissions limit equal to 0 scfh. 

 Regulatory Option 2. Establish an emissions limit equal to 6 scfh. 

6.5.1 Evaluation of Regulatory Options 

By establishing an emission limit of 0 scfh, facilities would most likely need to install instrument 

air systems to meet the threshold limit. Because facilities located in the transmission and storage segment 

might not always have sufficient electrical service to install an instrument air systems, this option would 

not be practically feasible in all situations. In addition, the cost of supplying electric power (which is 

highly variable) would need to be considered, which would likely render the cost of this control option to 

be unreasonable. Therefore Regulatory option 1 was rejected for facilities in the transmission and storage 

segment. 

Regulatory Option 2 would establish an emission limit equal to the maximum emissions allowed 

for a low-bleed device in the transmission and storage segment. This would most likely be met by the use 

of low-bleed controllers in place of a high-bleed controller, but allows flexibility in the chosen method of 
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meeting the requirement. In the key instances related to pressure control that would disallow the use of a 

low-bleed device, specific monitoring and recordkeeping criteria would be required to ensure the device 

function dictates the precision of a high bleed device. Therefore, Regulatory Option 2 was accepted for 

locations outside of natural gas processing plants. 

6.5.2 Nationwide Impacts of Regulatory Options 

Table 6-9 summarize the costs impacts of the selected regulatory option for the natural gas 

transmission and storage segment. It is estimated to affect 210 new transmission and storage pneumatic 

controllers per year with nationwide capital cost of $47,670 and annual costs of $5,250 for projected year 

2020. For the projected year 2025, we estimate the number of new affected facilities for the years 2020 

through 2025. As mentioned above, because the natural gas processed by the facilities within the 

transmission and storage segment is not necessarily owned by the operator, no gas savings is considered 

for this segment. 

Table 6-9. Nationwide Cost and Emission Reduction Impacts for Selected Regulatory Option 

Number of 

Affected 

Facilitiesa

Capital Cost 

Per 

Controllerb 

($)

Annual 

Costs 

($/year) 

Nationwide Emission 

Reductions 

 (tpy)

Total Nationwide Costs 

($/year) 

CH4 VOC Capital Cost Annualized Cost

Projected Year 2020 

210 $227 $25 585 16 $47,670 $5,250 

Projected Year 2025 

1,260 $227 $25 3,511 97 $286,020 $31,680 

a. The number of sources subject to NSPS for the natural gas transmission and storage segment represent the number of new 

controllers expected per year reduced by 20 percent. This is consistent with the assumption that 80 percent of high bleed 

controllers can be replaced with a low bleed device. It is assumed all new sources would be installed as a high bleed for 

these segments. 

b. The capital cost is equal to the incremental cost of a low bleed device versus a new high bleed device. 

 
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7.0 PNEUMATIC PUMPS 

The natural gas industry uses a variety of pneumatic gas powered pumps where there is no reliable 

electrical power to “control processing problems and protect equipment.”73 Pneumatic pumps are “small 

positive displacement, reciprocating units used throughout the oil and natural gas production sector to 

inject precise amounts of chemicals into process streams [or for freeze protection glycol circulation].”74

Most chemical injection pumps (CIPs) fall into two main types: diaphragm, generally for heat tracing or 

plunger/piston, generally for chemical and methanol injection. This chapter describes pneumatic pumps 

including their function and associated emissions. Options available to reduce emissions from pneumatic 

pumps are presented, along with costs, emission reductions, and secondary impacts. Finally, this chapter 

discusses considerations in developing regulatory alternatives for pneumatic pumps. 

7.1 Process Description 

In many situations across all segments of the oil and gas industry, pneumatic pumps make “use of 

gas pressure where electricity is not readily available.”75 In the production segment, the supply gas is 

mostly produced natural gas, whereas in processing, the supply gas may be compressed air. In these gasdriven pneumatic pumps, characteristics that affect CH4 emissions include “the frequency of operation, the 

size of the unit, the supply gas pressure, and the inlet CH4 composition.”76 

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 

“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.”77 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. CIPs, i.e. piston/plunger pumps or small diaphragm pumps, inject small 

desired 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. 

The piston and diaphragm 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 

                                                            

73 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 13: Chemical Injection Pumps. Prepared 

for the GRI and EPA. EPA-600/R-96-080b. June 1996. 

74 See footnote 48. 

75 Ibid. 

76 Ibid. 

77 U.S. EPA OAQPS. Oil and Natural Gas Sector Pneumatic Devices. April 2014.
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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 the pump is either directly discharged into 

the atmosphere or is recovered and used as a fuel gas or stripping gas.”78 

Chemical injection pumps work by allowing a fluid to flow into an enclosed cavity from a lowpressure 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. This complete movement represents one full stroke.79

Typical chemicals injected in an oil or 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.80 

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 stroke has the opposite effect, decreasing the volume 

and increasing the pressure of the chamber to move out fluid.81 

In addition, not all pneumatic pumps are gas-driven. These “non-natural-gas driven” pneumatic 

pumps can be mechanically operated or use sources of power other than pressurized natural gas, such as 

compressed “instrument air.” Because these devices are not natural gas-driven, they do not directly release 

natural gas or VOC emissions. However, these systems have other energy impacts, with associated 

                                                            

78 See footnote 48. 

79 Ibid. 

80 Ibid. 

81 GlobalSpec. Diaphragm Pumps Information. Available at 

http://www.globalspec.com/learnmore/flow_transfer_control/pumps/diaphragm_pumps. 
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secondary impacts related to generation of the electrical power required to drive the instrument air 

compressor system. Instrument air systems are feasible only at oil and natural gas locations where the 

devices can be driven by compressed instrument air systems and have electrical service sufficient and 

reliable enough to power an air control system. This analysis assumed that natural gas processing plants 

and natural gas transmission stations are the only facilities in the oil and natural gas source category highly 

likely to have electrical service sufficient to power an instrument air system, and that most existing gas 

processing plants use instrument air instead of gas-driven devices.82 The application of electrical controls 

is further elaborated in Section 7.3. 

7.1.1 Emissions Data and Information 

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 study. 

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

Report Name Affiliation Year of 

Report 

Number of 

Devices 

Emissions 

Information 

Control 

Information

GHG Mandatory Reporting Rule EPA 2012 Nationwide X 

Inventory of U.S. GHG 

Emissions and Sinks: 1990-2012 EPA 2012 Nationwide/ 

Regional X 

CH4 Emissions from the Natural 

Gas Industry GRI/EPA 1996 Nationwide X 

CH4 Emissions from the 

Petroleum Industry EPA 1999 Nationwide X 

Natural Gas STAR Program EPA 2012 Study 

Specific X X 

7.1.1.2 Representative Pneumatic Pump Emissions 

The CH4 emission estimates for pneumatic pumps are separated into two categories for the 

GRI/EPA reports; CIPs (GRI/EPA, 1996d) and gas-assisted glycol pumps (GRI/EPA, 1996f). A summary 

of the report on CIPs is provided in the following sections. 

                                                            

82 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic Devices. Prepared for the 

Gas Research Institute and Environmental Protection Agency. EPA-600/R-96-080k. June 1996.
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For this analysis, the EPA consulted information in the appendices of the Natural Gas STAR 

Lessons Learned document on pneumatic pumps83,84, Subpart W of the GHG Reporting rule85, U.S. GHG 

Natural Gas and Petroleum Inventories86, and U.S. EPA GRI Report87. Subpart W and U.S. GHG 

Inventories use the emission factors form the U.S. EPA GRI Report. Similarly, EPA determined that the 

best available emissions factors for pneumatic pumps are presented in the U.S. EPA GRI Report. For the 

activity factor, EPA determined the best available data is the U.S. EPA GHG Inventory. Since publication 

of the white paper, additional data have become available on emissions from pumps, including GHGRP 

2013 reporting year data. In 2013, reported methane emissions from chemical injection pumps in the 

production segment were 3,046,012 tons of CO2e. 

The basic approach used for this analysis was to first approximate CH4 emissions from the average 

pneumatic pump in each industry segment and then estimate VOC and HAP using the gas composition as 

was determined for the NSPS.88 The specific ratios from the gas composition used for this analysis were 

0.278 lbs VOC per pound CH4 per pound CH4 in the production and processing segments, and 0.0277 lbs 

VOC per pound CH4 in the transmission and storage segment. Table 7-2 summarizes the estimated bleed 

emission factors for a representative pneumatic pump by industry segment. 

                                                            

83 U.S. Environmental Protection Agency. Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air. Office of Air 

and Radiation: Natural Gas Star. Washington, DC. February 2004. 

84 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. 

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

Systems – Subpart W. Washington, DC. November 2010. 

86 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 87 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). 88 See footnote 5. 
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Table 7-2. Average Bleed Emission Estimates Per Pneumatic Pump 

Segment/Pump Type 

Emission Factor

(scf/hr)a

Emission factor 

(Mcf/year)b

Emission Factor 

(tpy)c

Emission Factor 

(tpy)d 

Natural Gas CH4 CH4 VOC 

Production 

Diaphragm 22.45 163 3.46 0.96 

Piston 2.48 18 0.38 0.11 

Processing 

Small Diaphragm 22.45 163 3.46 0.96 

Medium Diaphragm 22.45 163 3.46 0.96 

Large Diaphragm 22.45 163 3.46 0.96 

Small Piston 2.48 18 0.38 0.11 

Medium Piston 2.48 18 0.38 0.11 

Large Piston 2.48 18 0.38 0.11 

Transmission 

Diaphragm 20.05 163 3.46 0.1 

Piston 2.21 18 0.38 0.01 

Storage 

Diaphragm 20.05 163 3.46 0.1 

Piston 2.21 18 0.38 0.01 

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 8760 hrs/yr and volumetric fraction of methane is 82.9% of natural gas in natural gas production and processing and 

92.8% of natural gas in natural gas transmission and underground storage. 

c. Assumes density of methane is 19.26 g/scf. 

d. Assumes 0.27797 VOC content per pound of methane in natural gas production and processing and 0.0277 VOC content per 

pound of methane in natural gas transmission and underground storage. 

7.2 Nationwide Emissions from New Sources 

7.2.1 Approach 

Nationwide emissions from newly installed natural gas CIPs for a typical year were calculated by 

estimating the count of CIPs installed in a typical year and multiplying by the estimated annual emissions 

per device listed in Table 7-2. The count of new CIPs installed for a typical year was determined for each 

segment of the industry including natural gas production (which includes natural gas gathering and 

boosting), natural gas processing, and natural gas transmission and storage. The methodologies that 

determined the estimated count of new CIPs installed in a typical year is provided below. 

7.2.2 Population of CIPs Installed Annually 

For the natural gas production segment, which includes natural gas gathering and boosting, the 

count of new CIPs installed in a typical year was estimated by reviewing the annual count of CIPs from 
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the year 1990 to 2012 reported in the GHG Inventory for the natural gas and oil production facilities and 

determining the rate of change in the count of CIPs in each inventory over this period. For all the years, 

the annual counts of new CIPs installed between two years were not consistent. The average change for 

the entire period was estimated to be 877 for natural gas facilities and -161 for oil facilities. Additionally, 

the average change over the last 10 years was estimated to be 1480 for natural gas and 803 for oil. Because 

of the fluctuation in the count of new CIPs from the years 1990 to 2012, it was assumed that the 10-year 

average change represented a better estimate of the current growth of CIPs. Therefore, for this analysis, 

the counts of new CIPs that would be affected sources under the proposed NSPS in each of the years 2012, 

2020 and 2025 were estimated to be 1,480 for natural gas and 803 for oil. 

To forecast the count of CIPs replaced in a typical year, age and count of gas and oil wells for 2013 

were extracted from DI Desktop®. The age of the pneumatic pump was assumed to be the age of the well. 

Based on expert judgment, the average lifetime of a pneumatic pump was assumed to be 10 years. 

Therefore, a portion of CIPs that reached 10 years in a particular year were assumed to be replaced that 

year. For 2020, the typical year for this analysis, the replacement count for CIPs was estimated to be 340 

diaphragm pumps and 340 piston pumps. 

The GHG Inventory89 does not estimate any emissions from CIPs for the natural gas processing, 

natural gas transmission and storage segments. CIP data are not reported in GHGRP for these segments. 

For this analysis, the EPA assumed that CIPs are not used in these segments. 

Once the population counts of pneumatic pumps in each segment were established, the count of 

CIPs was split into diaphragm and piston. Similar to the assumption used in the EPA/GRI Report,90 for 

new and replaced pumps for each segment we assumed 50 percent of the pumps to be diaphragm and 50 

percent of the pumps to be piston pumps. Table 7-3 below summarizes the estimated count of new pumps 

installed per year. 

                                                            

89 See footnote 80 

90 See footnote 81. 
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Table 7-3. Estimated Count of Pneumatic Devices Installed in a Typical Year 

Segment/Pump Type Number of New 

Pumps

Production/Diaphragm 1,480 

Production/Piston 1,480 

Processing/Diaphragm and Piston 0 

Transmission/Diaphragm and Piston 0 

Storage/Diaphragm and Piston 0 

7.2.3 Emission Estimates 

Nationwide baseline emission estimates for pneumatic pumps for new sources in a typical year are 

summarized in Table 7-4 by industry segment and pump type. 

Table 7-4. Nationwide Baseline Emissions from Representative Chemical Injection Pumps Installed 

in a Typical Year for the Oil and Natural Gas Industry 

Segment/Pump Type Number of 

New Pumpsa

Emission Factor 

(tpy)b

Nationwide Emissions 

(tpy) 

CH4 VOC CH4 VOC 

Production/Diaphragm 1,480 3.46 0.96 5,121 1,423 

Production/Piston 1,480 0.38 0.11 562 156 

Processing/Diaphragm 0 3.46 0.9600 0 0 

Processing/Piston 0 0.38 0.11 0 0 

Transmission/Diaphragm 0 3.46 0.1 0 0 

Transmission/Piston 0 0.38 0.01 0 0 

Storage/Diaphragm 0 3.46 0.1 0 0 

Storage/Piston 0 0.38 0.01 0 0 

Totals 5,683 1,579 

Total Production 5,683 1,579 

Total Processing 0 0 

Total Transmission 0 0 

Total Storage 0 0 

a. From Table 7-2. 

b. From Table 7-3. 

7.3 Control Techniques 

Gas-driven chemical pumps emit CH4 during normal operations. Depending on the type of pump, 

and the constraints of the location, companies can utilize a variety of technologies to reduce emissions. 

Table 7-5 provides a summary of these options for reducing emissions from gas-driven chemical pumps 

including: instrument air, solar, electricity, or routing emissions to a gas capture system or flare. 
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In situations where the replacement of gas-driven pumps with electric, solar and instrument air 

pumps is not possible, emissions can be captured via a vapor recovery unit (VRU), or sent to a combustion 

device. Identified emission control options for gas-driven pumps are described in the following section. 
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Table 7-5. Alternative Control Options for Gas-Driven Pumps 

Option Description Applicability/Effectiveness Est

Convert to Solar Pumps 

Solar power cells can generate electricity to power the pump. Solar cells can utilize a back-up power system to ensure reliability. 

Solar powered pumps are only reliable in areas where the sun can power the pump reliably. These devices, when applicable can result in 100 percent reduction in emissions where applicable. 

Capital csolar pum$2,300 p

Covert to Electric Pumps 

Electric pumps can be used where a reliable source of electricity is available at the facility. 

Electric powered pumps are only reliable with a constant supply of electricity. Overall, this option is applicable in niche areas but can achieve 100 percent reduction in emissions where applicable. 

Capital c$1,807 tcosts and maintenadevice. 

Convert to Instrument Air9186

Instrument air systems can be used by replacing compressed air for the gas in pumps. These systems include a compressor, electrical power source, air dehydrator (depending on the type of pump), and volume tank. 

Instrument air systems reduce emissions by 100 percent by replacing natural gas with instrument air. This technology offers economies of scale, where it is more economical at facilities with more pneumatic pumps. The system requires a reliable source of electrical power. 

A complprovided costs are compreslabor and 

Route natural gas to an Existing Control Device 

Routing natural gas from a gas-driven pump entails piping to a control device inlet stream. 

Routing natural gas pumps to a combustion device reduces VOC and CH4

emissions by 95 percent. Routing natural gas to a control device is an option when a control device with available capacity is present on site. 

Capital cdependinpipeline approximdevice. 

Route natural gas to Newly Installed Control Device 

Routing natural gas from a gas-driven pump to a control device requires installation of a control device and piping between the pump and the control device. 

Routing natural gas-driven pumps to a combustion control device typically reduces VOC and CH4 emissions by 95 

percent. Routing natural gas to a control device is an option when utilities (i.e., electricity, water) needed to run the device are readily available. 

Capital capproximannual c

Route Natural Gas to Existing Gas Capture System 

Routing natural gas from a gas-driven pump entails piping to a VRU. 

Routing natural gas-driven pumps to a VRU reduces VOC and CH4 emissions 

through gas capture where emission reduction efficiencies are typically 95 percent. Routing natural gas to a VRU is 

Capital cdependinpipeline estimate$1,500 p
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Option Description Applicability/Effectiveness Est

applicable when an existing VRU with available capacity is present on site. 

Route Natural Gas to Newly Installed Gas Capture System 

Routing natural gas from a gas-driven pump to a gas capture system requires the installation of a gas capture system such as a VRU and piping between the pump and the capture system. There must also be an onsite use for the captured gas such as a combustion engine; otherwise, a control device would be required. 

Installing a VRU and sending natural gas from pumps results in emission reductions of approximately 95percent. This option is most effective at facilities with a large number of pumps, and other emission sources that can also be sent to the VRU. 

Capital capproximannual c
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7.3.1 Solar Pumps 

7.3.1.1 Emissions Reduction Potential

Solar pumps provide the same functionality as gas-driven pumps, and can be utilized at remote 

sites where a reliable source of electricity is not available. Solar-charged DC pumps can handle a range of 

throughputs up to 100 gallons per day with maximum injection pressure around 3,000 pounds per square 

inch gage (psig) and have zero natural gas emissions. Replacing a natural gas-driven pump with a solar 

pump can result in 100 percent reduction in methane and VOC emissions. We estimate converting natural 

gas-driven chemical pumps to solar-powered pumps can reduce CH4 emissions by 3.46 tons per year per 

diaphragm pump and 0.38 tons per year per piston pump for all segments.91 Based on the gas composition 

for natural gas in the production segment, we estimate that replacement of a natural gas-driven pump with 

a solar-powered pump will reduce VOC emissions by 0.96 tons per year per diaphragm pump and 0.11 

tons per year per piston pump. Likewise, for the transmission and storage segment, we estimate that 

replacement of a natural gas-driven pump with a solar-powered pump will reduce CH4 emissions by 3.46 

tons per year per diaphragm pump and 0.38 tons per year per piston pump VOC emissions by 0.1 tons per 

year per diaphragm pump and 0.01 tons per year for a piston pump. 

7.3.1.2 Effectiveness 

Replacing a natural gas-driven pump with a solar pump can result in 100 percent reduction in 

methane and VOC emissions and is feasible in regions where there is sufficient sunlight to power the 

pump, and backup power is not required. Solar-powered pumps are typically low volume pumps that inject 

methanol or corrosion inhibitors into a well with typical volumes ranging from 6 to 8 gallons per day. In 

addition to low volume pumps, large volume pumps used to replace natural gas-assisted circulation pumps 

for glycol dehydrators can also be converted to solar. 

7.3.1.3 Cost Impacts 

The primary costs associated with conversion to solar pumps are the initial capital expenditures 

and annual maintenance costs which are typically lower than gas-driven pump maintenance costs. The cost 

being attributed to the replacement of pneumatic pumps with solar powered pumps includes the capital 

cost of replacing the pump with a solar powered pump and operating cost. The operating costs are 

estimated to be 10 percent of the capital costs. Based on Natural Gas STAR document, “PRO Fact Sheet: 

Convert Natural Gas-Driven Chemical Pumps”92, the cost for solar-powered electric pumps are 

                                                            

91 U.S. EPA. PRO Fact Sheet No. 202. Convert Natural Gas-Driven Chemical Pumps. Available at 

http://www.epa.gov/gasstar/documents/convertgasdrivenchemicalpumpstoinstrumentair.pdf. 92 See footnote 77. 
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approximately $2,000 with solar panels having a lifespan of 15 years and electric motors lasting 5 years. 

The total capital cost, including installation and labor are $2,227 (2012 dollars). We estimate there would 

be no additional annual operating cost 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 cost of replacing 

natural gas-driven pump with a solar pump is $317. In addition, the use of electric pumps will have 

savings realized from the 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 for 

diaphragm pumps and $72 per year per piston pump. 

7.3.1.4 Secondary Impacts 

No secondary impacts from conversion to solar powered pumps are expected. 

7.3.2 Electric Pumps 

7.3.2.1 Emission Reduction Potential 

Electric pumps also provide the same functionality as gas-driven pumps, and are only restricted by 

availability of a reliable source of electricity. Electric pumps have zero natural gas emissions, as 

summarized in Table 7-6, and converting gas-driven chemical pumps to an electric pump can reduce CH4

emissions by an estimated 3.46 tons per year per diaphragm pump and 0.38 tons per year per piston pump. 

Based on the gas composition for natural gas in the production segment, we estimate that replacement of a 

pneumatic pump with an electric pump will reduce VOC emissions by 0.96 tons per year per diaphragm 

pump and 0.11 tons per year for a piston pump. Likewise, for the transmission and storage segment, we 

estimate that replacement of a pneumatic pump with an electric pump will reduce CH4 emissions by an 

estimated 3.46 tons per year per diaphragm pump and 0.38 tons per year per piston pump and VOC 

emissions by 0.1 tons per year per diaphragm pump and 0.01 tons per year for a piston pump. 

7.3.2.2 Effectiveness 

Replacing a natural gas-driven pump with an electric pump can result in 100 percent reduction in 

emissions. However, use of electric pumps requires a reliable source of electricity. These pumps are, 

therefore, more common at processing plants or large dehydration facilities that have access to reliable 

power. 
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7.3.2.3 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”93 the cost of electric 

pumps to replace diaphragm pumps is $4,647 and to replace a piston pump is $1,819 in 2012 dollars 

depending on the horsepower of the unit.94 The annual operating costs for the electric pumps is estimated 

to be $293. Annualizing the capital cost over the life expectancy of the pump at a 7 percent discount rate, 

the annual cost for replacing a natural gas-driven pump with an electric pump is $954 for diaphragm 

pump, and $506 for a piston. In addition, the use of electric pumps will have savings realized from the 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 save of 22 Mcf per year. The value of the natural gas saved 

based on $4.00 per Mcf would be $786 per year for diaphragm pumps and $87 per year per piston pump. 

7.3.2.4 Secondary Impacts 

The secondary impacts from electric pumps are indirect, variable and dependent on the electrical 

supply used to power the compressor. No other secondary impacts are expected. 

7.3.3 Instrument Air System 

7.3.3.1 Process Description 

Instrument air systems require a compressor, power source, dehydrator, and volume tank. The 

same natural gas-driven pumps can be used for natural gas and compressed air, without altering any of the 

parts of the pump, but instrument air eliminates the emissions of natural gas. All facilities that have access 

to a reliable source electricity can install an instrument air system. A description of each of the 

components as described in the Natural Gas STAR document, “PRO Fact Sheet: Convert Gas Pneumatic 

Controls to Instrument Air”:95

 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 of control devices operated by the 

system, and the typical bleed rates of these devices. The compressor is usually driven by an 

                                                            

93 See footnote 87. 

94 U.S. EPA. Lessons Learned. Replacing Gas-Assisted Glycol Pumps with Electric Pumps. Available online - 

http://www.epa.gov/gasstar/documents/ll_glycol_pumps3.pdf. 

95 See footnote 87.
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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 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, 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 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 

CH4 emissions and energy consumption. Small natural gas powered fuel cells are also being 

developed. 

 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. 

 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, without affecting 

the process control functions. 

7.3.3.2 Emission Reduction Potential and Effectiveness 

Instrument air eliminates all emissions from natural gas-driven 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 functioning.96 Because all emissions can be avoided 

by converting natural gas-driven chemical pumps to instrument air, CH4 emissions can be reduced by an 

estimated 3.46 tons per year per diaphragm pump and 0.38 tons per year 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 tons per year per diaphragm pump 

and 0.11 tons per year for a piston pump. Likewise, for the transmission and storage segment, we estimate 

                                                            

96 U.S. Environmental Protection Agency. Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air. Office of Air 

and Radiation: Natural Gas Star. Washington, DC. February 2004.
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that replacement of a pneumatic pump converted to instrument air will reduce CH4 emissions can be 

reduced by an estimated 3.46 tons per year per diaphragm pump and 0.38 tons per year per piston pump 

and VOC emissions by 0.1 tons per year per diaphragm pump and 0.01 tons per year for a piston pump. 

7.3.3.3 Cost Impacts 

As stated earlier, 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 natural 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.97 

For natural gas processing, the cost of emissions reduction of the three representative instrument 

air system sizes was evaluated 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. As was discussed in the 2011 NSPS TSD, we assume that existing processing plants 

have an instrument air system in place, including backup systems, and that the cost of adding additional air 

load to the system would be confined to the incremental cost of upgrading or replacing the compressor and 

connecting the natural gas-driven pumps to the system. Therefore, for this analysis, the cost being 

attributed to the replacement of natural gas-driven pumps with air-driven pumps includes the annualized 

cost of replacing or adding a compressor and installation of the associated piping to connect the pumps to 

the existing system, and the associated energy costs for operating the new compressor. The size of the 

compressor required would depend on the additional air load required for the instrument air system to 

handle the pneumatic pumps. 

Because we have no data to characterize the number and types of gas-driven pumps at natural gas 

processing plants, we developed several model plant scenarios that would likely cover a reasonable range 

of the numbers and types of pumps that might be found at natural gas processing plants. The model plants 

represented processing plants with 4, 10, 20, 50 and 100 total pumps. Because there is a significant 

variation in emissions profiles between natural gas-driven diaphragm and piston pumps, we also 

evaluated, within each model plant, three distribution scenarios for the pumps (i.e. 50 percent diaphragm 

and 50 percent piston, 25 percent diaphragm and 75 percent piston, and 75 percent diaphragm and 25 

                                                            

97 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 13: Chemical Injection Pumps. Prepared 

for the Gas Research Institute and Environmental Protection Agency. EPA-600/R-96-080b. June 1996.
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percent piston.). In our analysis, we determined the total additional air capacity needed based on the 

estimated natural gas emission rate for the two types of natural gas-driven pumps, and based on the model 

plant scenarios, determined the volume of additional air capacity that would need to be addressed by the 

compressor. We then based or analysis on the use of 90 percent of available capacity of the system. We 

determined that there were basically three sizes (small, medium and large) compressors that would address 

the range of model plants. Table 7-6 summarizes the model plant analysis of required system capacity and 

potential emissions reductions. The compressor costs used in our analysis were drawn from the costing 

analysis conducted for the 2011 NSPS proposal for instrument air systems for pneumatic controllers (See 

Section 5 of the 2011 TSD). We estimated costs, including operating costs, at three size levels; small, 

medium and large. Table 7-7 summarizes the cost replacement of the various size compressors into an 

existing instrument air system. 

Because gas emissions are avoided, the use of an instrument air system to control natural gasdriven pumps will have natural gas savings realized from the 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 save of 22 Mcf per year. The value of the natural gas saved based on $4.00 per Mcf would be 

$786 per year per diaphragm pumps and $72 per year per piston pump. 

7.2.3.4 Secondary Impacts 

The secondary impacts from instrument air systems are indirect, variable and dependent on the

electrical supply used to power the compressor. No other secondary impacts are expected. 
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Table 7-6. Model Plant Characterization for Replacing Gas-Driven Pumps with Instrument A

Model 

Plant Size 

Annual 

Compressor 

Costa

Pump 

Distribution

Scenariob

Total 

Number 

of Pumps 

Number of 

Diaphragm 

Pumps 

Number 

of Piston 

Pumps 

Total 

Additional 

Air 

Capacity 

Required 

(scf/hour) 

Gas Savedc 

(Mcf) 

E

M

Small 10,051 

50/50 4 2 2 50 49.8 

75/25 4 3 1 70 69.8 25/75 4 1 3 30 29.9 

Medium 

Small 10,051 

50/50 10 5 5 125 124.6 

75/25 10 7.5 2.5 175 174.5 25/75 10 2.5 7.5 75 74.7 

Medium 32,271 

50/50 20 10 10 249 249.2 

75/25 20 15 5 349 349.1 25/75 20 5 15 149 149.4 

Medium 

Large 72,394 

50/50 50 25 25 623 623.1 

75/25 50 37.5 12.5 873 872.7 25/75 50 12.5 37.5 374 373.5 

Large 72,394 

50/50 100 50 50 1,246 1246.2 

75/25 100 75 25 1,745 1745.4 25/75 100 25 75 747 747.0 

a. See Table 7-7 for the compressor cost analysis. b. Allocation of type of pumps (i.e., 50/50 is half the pumps are diaphragm and half are piston, 75/25 is 75% of the pumps are diaphragm c. Based on raw gas emissions of 22.45 scf/hr for a diaphragm pump and 2.48 scf/hr for a piston pump, resulting in $786 savings per diapper piston pump. d. Based on 3.36 tons per year of methane and 0.96 tons per year of VOC per diaphragm pump and 0.36 tons per year of methane and 0.1piston pump. 
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Table 7-7. Cost of Compressor Replacement for Existing Instrument Air System 

Compresso

r 

Size

Air 

Capacity 

(scf/hour) 

Capital 

Cost 

($) 

Capital Cost 

+ 

Installationa

(2008) 

Total 

Capital 

Cost 

($2012) 

Annualized 

Cost 

($) 

Labor 

Cost 

($2008) 

Power 

Cost 

($2008) 

Total 

O&M 

($2008) 

(

Small 135 $3,772 $5,658 $5,999 $854 $1,334 $7,340 $8,674 

Medium 562 $18,855 $28,282 $29,989 $4,270 $4,333 $22,075 $26,408 $

Large 1,350 $33,183 $49,775 $52,779 $7,515 $5,999 $55,188 $61,187 $

a. Installation cost is estimated to be 50 percent of capital cost. 
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7.3.4 Install or Route Gas to Combustion Device 

7.3.4.1 Emission Reduction Potential 

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 emitted, but rather combusts the gas 

volume. Costs for routing the natural gas to a combustion device are further described in Table 7-5. We 

estimate that capture and combustion device efficiency to be 95 percent reduction. Therefore, CH4

reductions are estimated to be 3.29 tons per year for a diaphragm pump and 0.36 tons per year for a piston 

pump. Based on the gas composition for natural gas in the production segment, we estimate that routing 

emissions to a combustion device will reduce VOC emissions by 0.91 tons per year per diaphragm pump 

and 0.1 tons per year for a piston pump. Likewise, for the transmission and storage segment, we estimate 

that routing emissions to a combustion device will reduce CH4 reductions by 3.29 tons per year per 

diaphragm pump and 0.36 tons per year for a piston pump VOC emissions by 0.09 tons per year per 

diaphragm pump and 0.01 tons per year for a piston pump. 

7.3.4.2 Effectiveness 

Capture systems combined with combustion devices are considered a reliable mechanism to reduce 

approximately 95 percent of emissions. Each combustion device requires a reliable ignition source where 

the average gas consumption per pilot burner is 70 scf per hour.98 Most processing plants or large 

dehydration facilities already have at least one existing combustion device. 

7.3.4.3 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 the analysis conducted for the 2012 NSPS for a 

combustion device to control emissions from storage vessels,99 the capital cost for installing a new 

combustion device is $32,301 in 2008 dollars. We estimate that the capital cost for installing a new 

combustion device is $34,250 and the annual operating costs are $17,001 in 2012 dollars. Based on the life 

expectancy for a combustion device, we estimate the annualized cost of installing a new combustion 

device to $21,877 using a 7 percent discount rate. We estimate the annualized cost of routing emissions to 

an existing combustion device to be $285 using a 7 percent discount rate. Because the gas captured is 

combusted there is no gas savings associated with use of a combustion device. 

                                                            

98 Ibid. 

99 U.S. EPA docket ID: EPA-HQ-OAR-2010-0505-0045. 
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7.3.4.4 Secondary Impacts 

There are secondary impacts from combustion of emissions routed from natural gas-driven 

pumps. The combustion of the recovered natural gas creates secondary emissions of hydrocarbons, NOX, 

CO2, and CO. A summary of the estimated secondary emission are presented in Table 7-8. No other 

wastes should be created or wastewater generated. 

Table 7-8. Secondary Impacts from Pneumatic Pumps Routed to a Combustion Device 

 a. Based on combustion of natural gas stream and AP-42 Total Hydrocarbons emission factors for industrial flares. 

b. Based on combustion of natural gas stream and AP-42 Carbon Monoxide emission factors for industrial flares. 

c. Based on combustion of natural gas stream and 40 CFR Part 98, subpart Y, Equation Y-2. 

d. Based on combustion of natural gas stream and AP-42 Nitrogen Oxides emission factors for industrial flares. 

e. Based on combustion of natural gas stream and AP-42 Particulate Matter emission factors for industrial flares. Assumes a 

“lightly smoking” flare. 

7.3.5 Install or Route Gas to VRU 

7.3.5.1 Emission Reduction Potential 

Use of a vapor recovery technology has the potential to reduce the emissions from natural gasdrive pumps by 100 percent if all vapor is recovered. However, the effectiveness of the gas capture system 

and downtime for maintenance would reduce capture efficiency and therefore, we estimate that routing 

emissions from a natural gas-driven pump to an existing VRU, or a newly installed VRU can reduce the 

gas emitted by approximately 95 percent, while at the same time, capturing the gas for beneficial use. We 

estimate that methane emissions reductions for routing gas to a VRU to be 3.29 tons per year for a 

diaphragm pump and 0.36 tons per year 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 

tons per year per diaphragm pump and 0.1 tons per year for a piston pump. Likewise, for the transmission 

and storage segment, we estimate that routing emissions to a VRU will reduce methane emissions by 3.29 

tons per year for a diaphragm pump and 0.36 tons per year for a piston pump and VOC emissions by 0.09 

tons per year per diaphragm pump and 0.01 tons per year per piston pump. 

7.3.5.2 Effectiveness 

VRUs are reliable, typically with a backup compressor system to allow for shutdowns and repairs. 

VRUs are more economical for facilities with multiple gas emission sources that can be routed to the 

Pump Type (tpy) 

THCa COb CO2

c NOxd PMe

Diaphragm 0.02 0.04 14 0.01 0 

Piston 0.002 0.004 2 0.001 0 
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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 or large dehydration facilities. 

7.3.5.3 Cost Impacts 

Routing natural gas to an existing VRU or installing a new VRU, have both capital costs and 

maintenance costs. Based on the analysis conducted for the 2012 NSPS for control of emissions from 

storage vessels100, the capital cost and installation costs for a VRU is estimated to be $98,186 in 2008 

dollars. We estimate the capital cost of installation of a VRU to be $104,111 and the annual operation and 

maintenance cost to be $9,932 in 2012 dollars. 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. The total annualized cost of a 

new VRU is estimated to be $24,755 based on a 7 percent discount rate. 

We estimate the cost of routing emissions to an existing VRU to be $2,000 in 2012 dollars. The 

annualized cost of routing gas to an existing VRU is estimated to be $285 based on a 7 percent discount 

rate. In addition, because there is potential for beneficial use of gas recovered through the VRU, we 

estimate an annual gas recovered as 187 Mcf per year per diaphragm pump and 21 Mcf per year per piston 

pump. The gas savings realized is estimated to be $749 per diaphragm pump and $84 per piston pump, per 

year based on $4.00 value per Mcf of gas recovered. 

7.3.5.4 Secondary Impacts 

The secondary impacts from use of a VRU are indirect, variable and dependent on the electrical 

supply used to power the VRU. No other secondary impacts are expected. 

7.4 Regulatory Options 

The affected facility definition for natural gas-driven pump is defined as a single natural gasdriven pump. Therefore, natural gas-driven pumps would be subject to a New Source Performance 

Standard (NSPS) at the time of installation. 

The control technologies evaluated for natural gas-driven pumps included options that provided 

for 100 percent emissions reductions. These options included replacing the pumps with solar-powered 

pumps or electric pumps or use of instrument air systems to eliminate natural gas emissions. Also 

evaluated were gas recovery and gas combustion technologies that would result in 95 percent emissions 

reductions. 

                                                            

100 Ibid. 
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The use of instrument air systems and electric pumps as a control alternative requires a consistent 

supply of electric power and use of solar-powered pumps and routing emissions to a VRU requires 

reliable supply of backup electrical power. Because reliable electric power is not considered to be 

universally available for production, gathering and boosting and transmission and storage locations these 

control technologies were determined to not be technically viable options for those segments. Because 

electric power is typically available at natural gas processing plants, those technologies are considered 

technically viable for the processing segment. 

Based on the costs and estimated emissions reductions for each of the viable emissions control 

alternatives, we further evaluated the cost per ton of emissions reduction for methane and VOC. The cost 

per ton of emissions reduced was calculated in two ways. The first method, or single-pollutant approach, 

allocated all of the costs to each pollutant separately. The second method, or the multipollutant approach, 

allocates costs among the pollutants that a given technology reduced (i.e., CH4 and VOC). This 

multipollutant approach is based on estimates of the percentage reduction expected for each pollutant. 

Based on the above considerations we evaluated the following regulatory alternatives 

 Regulatory Option 1. Require a zero emission standard for natural gas processing plants. 

 Regulatory Option 2. Require a 95 percent emissions reduction standard for production, 

gathering and boosting stations, transmission stations and storage facilities. 

 Regulatory Option 3. Require a 95 percent emissions reduction standard for production, 

gathering and boosting stations, transmission stations and storage facilities only where 

an existing control device is available. 

7.4.1 Evaluation of Regulatory Options 

Regulatory Option 1 would require a zero emission of methane and VOC from gas-driven pumps 

at natural gas processing plants. To attain this emission reduction, the facility would need to either 

replace the natural gas-driven pumps with solar-powered or electric pumps or use instrument air systems 

to replace natural gas-driven function with air-driven function. We evaluated the cost of control for each 

of these options based on the estimated emissions reductions as detailed above. 

Using the single-pollutant (allocate costs to each pollutant separately) for calculating cost of 

control, for the use of an instrument air system at natural gas processing plants we estimate the cost per 

ton of methane reduced to be between $374 and $2,185 and the cost per ton of VOC reduced was 

between $1,344 and $7,861 without considering gas savings. With gas savings, for the use of an 

instrument air system at natural gas processing plants, the cost per ton of methane reduced was $146 and 
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$1,957 and the cost per ton of VOC reduced was between $527 and $7,042. Using the multi-pollutant 

method of allocating cost between methane and VOC, we estimate the cost of control, without 

considering gas savings, ranged from $187 to 1,093 per ton of methane reduced and $672 and $3,930 per 

ton of VOC reduced. When considering gas savings, we found the cost of control to range from $73 to 

$979 per ton of methane reduced and $263 to $3,521 per ton of VOC reduced. The range of cost per ton 

is dependent on the size of the system/compressor needed for the facility. We estimate the cost of control 

for replacement of a natural gas-driven pump with either an electric pump or solar powered pumps to be 

between -$136 and $1,223 per ton of methane and between -$489 and $4,225 per ton of VOC, 

considering gas savings. We consider these costs to be reasonable. Based on these cost of control values 

for CH4 and VOC, Regulatory Option 1 was accepted for the natural gas processing segment. Tables 7-9 

through 7-12 summarize the cost of control for each of these options for the natural gas processing 

segment. 

Because the control technologies that produce zero emissions (or 100 percent reduction in 

emissions) (i.e., solar-powered and electric pumps and instrument air systems) are not technically viable 

alternatives for the production and transmission and storage segments, the available control technologies 

for those segments produce a 95 percent emission reduction. Therefore, the second regulatory option 

would require a 95 percent reduction in emissions at production sites, transmission stations and 

underground storage facilities. To attain this emission reduction, the facility could route emissions to a 

VRU or a combustion device. 

Again we calculated the cost of control for this option for each control technology by the singlepollutant and multi-pollutant methods described above. For the installation of a new VRU or combustion 

device, the cost per ton of methane and VOC reductions ranged from are $3,652 to over $1 million. The 

cost of control for a new combustion device was likewise unreasonable with the cost per ton of methane 

ranging between $3,328 to over $1 million. Based on these cost of control values for CH4 and VOC, 

Regulatory Option 2 was rejected for all segments. Tables 7-13 through 7-16 summarize the cost of 

control for Option 2 for all segments. 

Option 3 was evaluated to require 95 percent control of emissions in all segments only where an 

existing control device, capable of at least 95 percent reduction in emissions was available. The sole cost 

associated with this option that would be attributed to the emission reduction would be the cost of routing 

the pump emissions to the control device. As discussed above, we estimated that the cost to route 

emissions to either a VRU or a combustion device would be the same with a capital cost of 

approximately $2,000, which when annualized at a 7 percent discount rate, provided for an annualized 
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cost of $285. Based on this annualized cost, using the multi-pollutant approach of calculating cost of 

control, the cost of control for methane reductions with a VRU or a combustion device ranged from $43 

to $395 and the cost of control for VOC reductions ranged from $156 to $14,250. Considering natural 

gas savings when a VRU is used, the cost of control for methane emissions reductions is -$71 to $279 

and the cost of control for VOC reductions ranged from -$254 to $1,004. We found these methane costs 

to be reasonable and Option 3 was accepted for control of natural gas-driven pump emissions all 

segments. Tables 7-17 through 7-18 summarize the cost of control. 
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Table 7-9. Cost of Control for Use of Instrument Air Systems at Natural Gas Processing Plants - Si

Plant Size Compressor Costa Scenariob

Total 

Number 

of 

Pumps 

Total Gas 

Savedc 

(Mcf) 

Emissions Reductionsd 

(tpy) 

Cost of control 

(without savings) 

($/ton) 

Methane VOC Methane VOC 

Small $10,051 

50/50 4 49.8 7.7 2.1 $1,309 $4,708 

75/25 4 69.8 10.8 3.0 $934 $3,360 25/75 4 29.9 4.6 1.3 $2,185 $7,861 

Medium Small $10,051 

50/50 10 124.6 19.2 5.3 $523 $1,883 

75/25 10 174.5 26.9 7.5 $374 $1,344 25/75 10 74.7 11.5 3.2 $874 $3,144 

Medium $32,271 

50/50 20 249.2 38.4 10.7 $840 $3,023 

75/25 20 349.1 53.8 15.0 $600 $2,158 25/75 20 149.4 23.0 6.4 $1,403 $5,048 

Medium Large $72,394 

50/50 50 623.1 96.0 26.7 $837 $3,011 

75/25 50 872.7 134.5 37.4 $558 $2,007 25/75 50 373.5 57.5 16.0 $1,674 $6,022 

Large $72,394 

50/50 100 1246.2 192.0 53.4 $418 $1,505 

75/25 100 1745.4 269.0 74.8 NA - Beyo25/75 100 747.0 115.0 32.0 $837 $3,011 

a. See Table 7-7 for compressor cost analysis. b. Allocation of type of pumps (i.e., 50/50 is half the pumps are diaphragm and half are piston, 75/25 is 75% of the pumps are diaphragm c. Based on raw gas emissions of 22.45 scf/hr for a diaphragm pump and 2.48 scf/hr for a piston pump, resulting in $786 savings per diapper piston pump. d. Based on 3.36 tons per year of methane and 0.96 tons per year of VOC per diaphragm pump and 0.36 tons per year of methane and 0.1piston pump.
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Table 7-10. Cost of Control for Use of Instrument Air Systems at Natural Gas Processing Plants - Multi-poll

Plant Size Compressor Costa Scenariob

Total 

Number 

of 

Pumps 

Total Gas 

Savedc 

(Mcf) 

Emissions Reductionsd 

(tpy) 

Cost of Control 

 (without savings) 

($/ton) 

Methane VOC Methane VOC 

Small $10,051 

50/50 4 49.8 7.7 2.1 $654 $2,354 

75/25 4 69.8 10.8 3.0 $467 $1,680 25/75 4 29.9 4.6 1.3 $1,093 $3,930 

Medium Small $10,051 

50/50 10 124.6 19.2 5.3 $262 $942 

75/25 10 174.5 26.9 7.5 $187 $672 25/75 10 74.7 11.5 3.2 $437 $1,572 

Medium $32,271 

50/50 20 249.2 38.4 10.7 $420 $1,512 

75/25 20 349.1 53.8 15.0 $300 $1,079 25/75 20 149.4 23.0 6.4 $702 $2,524 

Medium Large $72,394 

50/50 50 623.1 96.0 26.7 $418 $1,505 

75/25 50 872.7 134.5 37.4 $279 $1,004 25/75 50 373.5 57.5 16.0 $837 $3,011 

Large $72,394 

50/50 100 1246.2 192.0 53.4 $209 $753 

75/25 100 1745.4 269.0 74.8 NA - Beyo25/75 100 747.0 115.0 32.0 $418 $1,505 

a. See Table 7-7 for compressor cost analysis. b. Allocation of type of pumps (i.e., 50/50 is half the pumps are diaphragm and half are piston, 75/25 is 75% of the pumps are diaphragm c. Based on raw gas emissions of 22.45 scf/hr for a diaphragm pump and 2.48 scf/hr for a piston pump, resulting in $786 savings per diapper piston pump. d. Based on 3.36 tons per year of methane and 0.96 tons per year of VOC per diaphragm pump and 0.36 tons per year of methane and 0.1piston pump.
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Table 7-11. Cost of Control for Replacement with Solar-Powered or Electric Pumps at Natural Gas Proce

pollutant 

Type of 

Pump 

Control 

Option 

Emission Factor 

(tpy/pump) 

Annualized 

Cost 

($) 

Natural Gas Cost 

Emission 

Factor 

(scf/h) 

Saved 

(Mcf/yr) 

Value 

($) 

without savings 

Methane VOC Methane VOC 

Diaphragm Electrica 3.46 0.96 4,175 22.45 197 $786 $276 $994 Diaphragm Solar 3.46 0.96 $2,000 22.45 197 $786 $92 $330 Piston Electrica 0.38 0.11 $4,175 2.48 22 $87 $1,452 $5,016 Piston Solar 0.38 0.11 $2000 2.48 22 $87 $834 $2,882 

a. For electric pumps, annual cost assumes a 5.0 BHP electric pump as reported in NGS LL "Replacing Gas-Assisted Glycol Pumps with 

installation is 10% of the capital cost. 

Table 7-12. Cost of Control for Replacement with Solar-Powered or Electric Pumps at Natural Gas Proce

pollutant Method 

Type of 

Pump 

Control 

Option 

Emission Factor 

(tpy/pump) 

Annualized 

Cost 

($) 

Natural Gas Cost 

Emission 

Factor 

(scf/h) 

Saved 

(Mcf/yr) 

Value 

 ($) 

without savings 

Methane VOC Methane VOC 

Diaphragm Electrica 3.46 0.96 $4,175 22.45 197 $786 $138 $497 Diaphragm Solar 3.46 0.96 $2,000 22.45 197 $786 $46 $165 Piston Electrica 0.38 0.11 $4,175 2.48 22 $87 $726 $2,508 Piston Solar 0.38 0.11 $2,000 2.48 22 $87 $417 $1,144

a. For electric pumps, annual cost assumes a 5.0 BHP electric pump as reported in NGS LL "Replacing Gas-Assisted Glycol Pumps with 

installation is 10% of the capital cost. 
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Table 7-13. Cost of Control for Routing Gas-Driven Pump Emissions to a VRU - Single-polluta

Pump Type/ 

Segment 

Emission Reductions 

(tpy/pump) Annualized Cost 

($) 

Natural Gas Cost o

($

Emission 

Factor 

(scf/h) 

Saved 

(Mcf/yr) 

Value

($) 

without savings 

Methane VOC Methane VOC 

Diaphragm Pumps 

Production 3.29 0.91 $24,755 22.45 187 $749 $7,531 $27,094 Processing 3.29 0.91 $24,755 22.45 187 $749 $7,531 $27,094 Transmission 3.29 0.09 $24,755 22.45 187 $749 $7,531 $271,888 Storage 3.29 0.09 $24,755 22.45 187 $749 $7,531 $271,888 

Piston Pumps 

Production 0.36 0.10 $24,755 2.48 21 $84 $68,574 $246,697 Processing 0.36 0.10 $24,755 2.48 21 $84 $68,574 $246,697 Transmission 0.36 0.01 $24,755 2.48 21 $84 $68,574 $2,475,60Storage 0.36 0.01 $24,755 2.48 21 $84 $68,574 $2,475,60

Note: No gas savings is attributed to transmission and storage. 
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Table 7-14. Cost of Control for Routing Gas-Driven Pump Emissions to a VRU - Multi-Polluta

Pump Type/ 

Segment 

Emission Reductions 

(tpy/pump) Annualized Cost 

($) 

Natural Gas Cost o

($

Emission 

Factor 

(scf/h) 

Saved 

(Mcf/yr) 

Value 

($) 

without savings 

Methane VOC Methane VOC 

Diaphragm Pumps 

Production 3.29 0.91 $24,755 22.45 187 $749 $3,766 $13,547 Processing 3.29 0.91 $24,755 22.45 187 $749 $3,766 $13,547 Transmission 3.29 0.09 $24,755 22.45 187 $749 $3,766 $135,944 Storage 3.29 0.09 $24,755 22.45 187 $749 $3,766 $135,944 

Piston Pumps 

Production 0.36 0.10 $24,755 2.48 21 $84 $34,287 $123,348 Processing 0.36 0.10 $24,755 2.48 21 $84 $34,287 $123,348 Transmission 0.36 0.01 $24,755 2.48 21 $84 $34,287 $1,237,80Storage 0.36 0.01 $24,755 2.48 21 $84 $34,287 $1,237,80

Note: No gas savings is attributed to transmission and storage. 
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Table 7-15. Estimated Cost of Control for Emission Reductions from Routing Gas-Drive Pump Emissions 

Device - Single-Pollutant Method 

Segment Type of Pump 

Emissions Reductions 

(tons/yr-pump) Annualized Cost ($2012) 

Cost of Co

 ($/ton

Methane VOC Methane 

Production Diaphragm 3.287 0.914 $21,877 $6,656 Processing Diaphragm 3.287 0.914 $21,877 $6,656 Transmission Diaphragm 3.287 0.091 $21,877 $6,656 Storage Diaphragm 3.287 0.091 $21,877 $6,656 Production Piston 0.361 0.100 $21,877 $60,602 Processing Piston 0.361 0.100 $21,877 $60,602 Transmission Piston 0.361 0.010 $21,877 $60,602 Storage Piston 0.361 0.010 $21,877 $60,602 
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Table 7-16. Estimated Cost of Control for Emission Reductions from Routing Gas-Drive Pump Emissions 

Device - Multi-pollutant Method 

Segment Type of Pump 

Individual Pneumatic Pump 

Emissions Reductions 

(tons/yr-pump) 

Annualized Cost 

($2012) 

Cost 

 

Methane VOC Methane 

Production Diaphragm 3.287 0.914 $21,877 $3,328 Processing Diaphragm 3.287 0.914 $21,877 $3,328 Transmission Diaphragm 3.287 0.091 $21,877 $3,328 Storage Diaphragm 3.287 0.091 $21,877 $3,328 Production Piston 0.361 0.100 $21,877 $30,301 Processing Piston 0.361 0.100 $21,877 $30,301 Transmission Piston 0.361 0.010 $21,877 $30,301 Storage Piston 0.361 0.010 $21,877 $30,301 
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Table 7-17. Cost of Control for Routing Gas-Driven Pump Emissions to an Existing Combustion D

- Single-pollutant Method 

Pump Type/ 

Segment 

Emission Reductions 

(tpy/pump) 

Annualized 

Cost 

($) 

Natural Gas Cost o

($

Emission 

Factor 

(scf/h) 

Saveda

(Mcf/yr) 

Value 

($) 

without savings 

Methane VOC Methane VOC 

Diaphragm Pumps 

Production 3.29 0.91 $285 22.45 187 $749 $87 $312 Processing 3.29 0.91 $285 22.45 187 $749 $87 $312 Transmission 3.29 0.09 $285 22.45 187 $749 $87 $3,130 Storage 3.29 0.09 $285 22.45 187 $749 $87 $3,130 

Piston Pumps 

Production 0.36 0.10 $285 2.48 21 $84 $789 $2,840 Processing 0.36 0.10 $285 2.48 21 $84 $789 $28,501 Transmission 0.36 0.01 $285 2.48 21 $84 $789 $28,501 Storage 0.36 0.01 $285 2.48 21 $84 $789 $28,501 

a. Applies to VRU only. There is no gas savings with a combustion device. 
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Table 7-18. Cost of Control for Routing Gas-Driven Pump Emissions to an Existing Combustion D

- Multi-Pollutant Method 

Pump Type/ 

Segment 

Emission Reductions 

(tpy/pump) Annualized Cost 

($) 

Natural Gas Cost o

($

Emission 

Factor 

(scf/h) 

Saveda

(Mcf/yr) 

Value 

($) 

without savings 

Methane VOC Methane VOC 

Diaphragm Pumps 

Production 3.29 0.91 $285 22.45 187 $749 $43 $156 Processing 3.29 0.91 $285 22.45 187 $749 $43 $156 Transmission 3.29 0.09 $285 22.45 187 $749 $43 $1,565 Storage 3.29 0.09 $285 22.45 187 $749 $43 $1,565 

Piston Pumps 

Production 0.36 0.10 $285 2.48 21 $84 $395 $1,420 Processing 0.36 0.10 $285 2.48 21 $84 $395 $1,420 Transmission 0.36 0.01 $285 2.48 21 $84 $395 $14,250 Storage 0.36 0.01 $285 2.48 21 $84 $395 $14,250 

a. Applies to VRU only. There is no gas savings with a combustion device. 
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7.4.2 Nationwide Impacts of Selected Regulatory Options 

We calculated the nationwide impacts of the selected options by considering the estimated 

affected population for each of the target years, the estimated emissions reductions per pneumatic pump 

controlled by the regulatory option and the annualized cost associated with that control option for that 

pump in that segment. 

For Option 1, based on the activity analysis presented above, we estimate there will be no new 

pneumatic pumps installed in the natural gas processing segment in either of the projected years 2020 or 

2025. Therefore, there will be zero nationwide emissions reductions and costs associated with Option 1. 

For Option 3, we estimated that there will be no new pneumatic pumps installed in the 

transmission and storage segment in either of the projected years 2020 or 2025. Therefore we estimate 

there will be no nationwide emissions reductions or cost impacts for Option 3 for those segments. 

We estimated that there will be 2,960 new or replaced pneumatic pumps installed in the 

production segment in the projected year 2020, with half of these pumps being diaphragm pumps and 

half being piston pumps. For the projected year 2025, we determined the affected population as those 

affected facilities from the years 2020 through and including 2025. Therefore, we estimate that 17,760 

new pneumatic pumps will be installed in the production segment by 2025, half of which will be 

diaphragm pumps and half will be piston pumps. 

Based on those activity numbers, the nationwide methane emission reductions in 2020 are 

estimated to be 4,865 tons per year of methane and 1,352 tons per year of VOC from diaphragm pumps 

and 534 tons per year of methane and 149 tons per year of VOC from piston pumps. The total 

nationwide emissions reductions, for the projected year 2020, are estimated to be 5,399 tons per year of 

methane and 1,501 tons per year of VOC. For the projected year 2025, we estimate the total nationwide 

emissions to be 32,395 tons per year of methane and 9,004 tons per year of VOC. 

The nationwide cost is based only on the Option 3 costs related to routing pump emissions to a 

combustion device or a VRU. We estimated that the annualized cost for routing pump emissions either to 

a combustion device or a VRU would be $285. Based on the estimated population of 2,960 pneumatic 

pumps in 2020, we estimate the nationwide cost to be $843,600 in 2020. The nationwide costs are 

estimated to be $5,061,600 in 2025. Table 7-19 summarizes the nationwide impacts. 
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Table 7-19. Nationwide Impacts for Gas-Driven Pumps for Selected Regulatory Option 

Regulatory Option 

Number of 

Pumps 

Subject to 

NSPS 

Annualized Cost 

($) 

Nationwide Emission 

Reductions 

(tpy) 

Nationwide 

Costs 

(million $) Methane VOC 

Projected Year 2020 

Option 1 

 Natural Gas Processing 0 $10,051 - $72,394 0 0 $0 

Option 3 

 Production 

 Transmission 

 Storage

2,960 

0 

0 

$285 

0 

0 

5,399 

0 

0 

1,501 

0 

0 

$0.84 

0 

0 

Projected Year 2025 

Option 1 

 Natural Gas Processing 0 $10,051 - $72,394 0 0 $0 

Option 3 

 Production 

 Transmission 

 Storage 

17,760 

0 

0 

$285 

0 

0 

32,395 

0 

0 

9,004 

0 

0 

$5.1 

0 

0 

 Secondary emissions impacts for Option 3 would include emissions resulting from the 

combustion of the recovered gas. Table 7-20 summarizes the nationwide secondary emissions for the 

projected year 2020 and 2025 for Option 3. 

Table 7-20. Nationwide Secondary Impacts from Pneumatic Pumps Routed to a Combustion Device 

a. Based on combustion of natural gas stream and AP-42 Total Hydrocarbons emission factors for industrial flares. 

b. Based on combustion of natural gas stream and AP-42 Carbon Monoxide emission factors for industrial flares. 

c. Based on combustion of natural gas stream and 40 CFR Part 98, subpart Y, Equation Y-2. 

d. Based on combustion of natural gas stream and AP-42 Nitrogen Oxides emission factors for industrial flares. 

e. Based on combustion of natural gas stream and AP-42 Particulate Matter emission factors for industrial flares. Assumes 

a “lightly smoking” flare. 

Segment (tpy) 

THCa COb CO2

c NOxd PMe

Projected Year 2020 

Production 25 66 23,616 12 0 

Projected Year 2025 

Production 150 396 141,696 72 0 
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8.0 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 air pollutant emissions from these compressors 

and provides emission estimates for reducing emission from these types of compressors. In addition, 

nationwide emissions estimates from new sources are estimated. Options for controlling pollutant 

emissions from these compressors are presented, along with costs, emission reductions, and secondary 

impacts. Finally, this chapter discusses considerations in developing regulatory alternatives for both 

reciprocating and centrifugal compressors. 

8.1 Process Description 

8.1.1 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 packing system will need to be replaced to prevent excessive leaking from the 

compression cylinder. 

8.1.2 Centrifugal Compressors 

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

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

compressors are primarily used for continuous, stationary transport of natural gas 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 absorbs some compressed natural gas which is released to the atmosphere 

during the seal oil recirculation process. 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 
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groves and springs. The opposing forces create a thin gap of high pressure gas between the rings through 

which little gas can leak. The rings do not wear or need lubrication because they are not in contact with 

each other. Therefore, operation and maintenance costs are typically lower for dry seals in comparison to 

wet seals. 

8.2 Emissions Data and Emissions Factors 

8.2.1 Summary of Major Studies and Emissions Factors 

There are a few studies that have been conducted that provide leak estimates from reciprocating and 

centrifugal compressors. These studies are provided in Table 8-1, along with the type of information contained 

in the study. 

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

Report Name Affiliation Year of 

Report

Activity 

Information

Emissions 

Information

Control 

Information

Inventory of U.S. GHG 

Emissions and Sinks: 1990-

2012a

EPA 2014 Nationwide X 

GHG Mandatory Reporting 

Rule and TSDb EPA 2013 Nationwide X 

Inventory of GHG 

Emissions and Sinks: 1990-

2012c

EPA 2014 Nationwide/ 

Regional X 

CH4 Emissions from the 

Natural Gas Industryd GRI/EPA 1996 Nationwide X 

Natural Gas STAR 

Programe,f EPA 1993-2010 Nationwide X X 

Natural Gas Industry CH4

Emission Factor 

Improvement Studyg

URS 

Corporation, UT 

Austin, and U.S. 

EPA 

2011 None Emission 

Factors Only 

Characterizing Pivotal 

Sources of CH4 Emissions 

from Natural Gas 

Production: Summary and 

Analysis of API and ANGA 

Survey Responsesh, i

API/ANGA 2012 Regional Xh

 

Economic Analysis of CH4

Emission Reduction 

Opportunities in the U.S. 

Onshore Oil and Natural 

Gas Industriesj

ICF 

International 

(Prepared for the 

Environmental 

Defense Fund) 

2014 Regional X X 

a. U.S. EPA. GHG Inventory: Emission and Sinks 1990-2012. Washington, DC. 

b. U.S. EPA. GHG Emissions Reporting From the Petroleum and Natural Gas Industry: Background TSD. Climate Change 

Division. Washington, DC. November 2014. 

c. U.S. EPA. Methodology for Estimating CH4 and CO2 Emissions from Natural Gas Systems. GHG Inventory: Emission and 

Sinks 1990-2008. Washington, DC. and U.S EPA. Methodology for Estimating CH4 and CO2 Emissions from Petroleum 
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Systems. GHG Inventory: Emission and Sinks 1990-2008. Washington, DC. 

d. National Risk Management Research Laboratory. GRI/EPA Research and Development, Methane Emissions from the 

Natural Gas Industry, Volume 8: Equipment Leaks. Prepared for the U.S. Department of Energy, EIA. EPA-600/R-96-080h. 

June 1996. 

e. U.S. EPA. Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR. 

EPA. 2006. 

f. U.S. EPA. Lessons Learned: Replacing Wet Seals with Dry Seals In Centrifugal Compressors. Natural Gas STAR. EPA.

2006. 

g. 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. 

h. API and America’s Natural Gas Alliance (ANGA). 2012. Characterizing Pivotal Sources of Methane Emissions from Natural 

Gas Production. Summary and Analysis of API and ANGA Survey Responses. Final Report. September 21, 2012. 

i. The API/ANGA study provided information on equipment counts that could augment nationwide emissions calculations. No 

source emissions information was included. 

j. ICF International. 2014. 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.

8.2.2 Representative Reciprocating and Centrifugal Compressor Emissions 

The methodology for estimating emission from reciprocating compressor rod packing was to use 

the CH4 emission factors referenced in the EPA/GRI study101 and the CH4-to-VOC ratio developed in the 

gas composition memorandum.102 The emission factors in the EPA/GRI document were expressed in 

thousand standard cubic feet per cylinder (Mscf/cyl), and were multiplied by the average number of 

cylinder per reciprocating compressor at each oil and gas industry segment. The volumetric CH4

emission rate was converted to a mass emission rate using a density of 41.63 lbs of CH4 per Mcf. This 

conversion factor was developed assuming that CH4 is an ideal gas and using the ideal gas law to 

calculate the density. A summary of the CH4 emission factors is presented in Table 8-2. Once the CH4

emissions were calculated, the ratio of VOC to CH4 was used to estimate VOC emissions. The specific 

VOC-to-CH4 ratios used for this analysis were 0.278 lbs VOC per pound of CH4 for the production and 

processing segments, and 0.0277 lbs VOC per pound of CH4 for the transmission and storage segment. A 

summary of the reciprocating compressor emissions are presented in Table 8-3. 

The compressor emission factors for wet seals and dry seals are based on data used in the GHG 

Inventory103. The wet seals CH4 emission factor was calculated based on a sampling of 48 wet seal 

centrifugal compressors. The dry seal CH4 emission factor was based on data collected by the Natural 

Gas STAR Program. The CH4 emissions were converted to VOC and HAP emissions using the same gas 

composition ratios that were used for reciprocating engines.104 

                                                            

101 National Risk Management Research Laboratory. GRI/EPA Research and Development, Methane Emissions from the 

Natural Gas Industry, Volume 8: Equipment Leaks. Prepared for the U.S. Department of Energy, Energy Information 

Administration. EPA-600/R-96-080h. June 1996. 

102 See footnote 6. 103 U.S. EPA. Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. GHG Inventory: Emission and 

Sinks: 1990-2012. Washington, DC. 2014.

104 Ibid
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Since publication of the white paper, additional data have become available on compressor 

emissions in transmission and storage, including reporting year 2013 data from GHGRP, and new 

measurement data from Subramanian et al. 2015. These data confirm the significant emissions from these 

sources, but indicate that emissions levels differ from those assumed in this analysis. In the 2013 GHGRP 

transmission and storage data set, reported emissions from reciprocating compressors are 2,247,626 tons 

CO2e of methane, and reported emissions from centrifugal compressors are 597,715 tons CO2e of 

methane. The Subramanian study, compared total average methane emissions per compressor in 

transmission and storage for both reciprocating and centrifugal compressors to those in the GHG 

Inventory, and found that the GHG Inventory had higher average emissions. 

Table 8-2. Methane Emission Factors for Reciprocating and Centrifugal Compressors 

Compresso

r Station

Reciprocating Compressors Centrifugal Compressors

CH4 Emission 

Factor 

(scf/hr-cylinder)

Average 

Number of 

Cylinders

Pressurized 

Factora

Wet Seal CH4

Emission Factor 

(scf/minute)

Dry Seals CH4 

Emission Factor 

(scf/minute)

Pressurized 

Factora

Transmission 57b 3.3 79.1% 47.7d 6d 30.0d

Storage 51c 4.5 67.5% 47.7d 6d 22.4d

a. Percent of hours per year that a compressor is pressurized. 

b. EPA/GRI. (1996). “Methane Emissions from the Natural Gas Industry: Volume 8 – Equipment Leaks.” Table 4-17. 

c. EPA/GRI. (1996). “Methane Emissions from the Natural Gas Industry: Volume 8 – Equipment Leaks.” Table 4-24. 

d. U.S. EPA. Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. GHG Inventory: Emission 

and Sinks: 1990-2012. Washington, DC. 2014. Annex 3.5 Table A-129. 

Table 8-3. Baseline Emission Estimates for Reciprocating and Centrifugal Compressors 

Compressor Location 

Baseline Emission Estimates 

(tpy)

CH4 VOC

Reciprocating Compressors

Transmission 27.1 0.75 

Storage 28.2 0.78 

Centrifugal Compressors (Wet Seals)

Transmission 157 4.34 

Storage 117 3.24 

Centrifugal Compressors (Dry Seals)

Transmission 19.7 0.546 

Storage 14.7 0.407 
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8.3 Nationwide Emissions from New Sources 

8.3.1 Overview of Approach 

The number of new affected facilities in the oil and natural gas source category was estimated 

using data from the GHG Inventory.105 The nationwide emissions estimates for new sources were then 

determined by multiplying the number of new sources for each oil and natural gas segment by the 

expected emissions per compressor based on the emission factor data presented in Table 8-3. A summary 

of the number of new reciprocating and centrifugal compressors for each of the oil and natural gas 

segments is presented in Table 8-4. 

8.3.2 Activity Data for Compressors in Transmission and Storage 

The number of reciprocating compressors and wet seal centrifugal compressors installed in the 

transmission and storage segment was estimated using the GHG Inventory. The number of new 

reciprocating compressors, wet seal centrifugal compressors, and dry seal centrifugal compressors 

installed in a given year was estimated by subtracting the prior year (e.g., 2011) from the given year's 

(e.g., 2012) total as represented in the Inventory. This difference was assumed to be the number of new 

compressors installed in the latter year (e.g., number of new compressors installed during 2012 equals the 

compressors reported in 2012 minus the compressors reported in 2011). A 10-year average was 

calculated based on the number of new compressors installed in 2003 through 2012 in order to determine 

the average number of new compressors installed in a typical year. An average was taken of only the 

years with an increase in compressors and rounded to the nearest whole number. The results of this 

analysis are shown in Table 8-4. 

                                                            

105 See footnote 6. 
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Table 8-4. Approximate Number of New Compressors in the Transmission and Storage Segment in 

a Typical Yeara

Compressor 

Location

Number of New 

Reciprocating 

Compressors

Number of New Centrifugal 

Compressors 

Wet Seal Dry Seal 

Transmission 24 0 2 

Storage 43 1 5 

 a. Estimates of the number of new compressors were rounded to the nearest whole number. 

8.3.3 Emission Estimates 

Nationwide baseline emission estimates for new reciprocating and centrifugal compressors are 

summarized in Table 8-5 by industry segment. 

Table 8-5. Nationwide Baseline Emissions for New Reciprocating and Centrifugal Compressors 

Compressor Location/Compressor Type

Nationwide Baseline Emissions 

(tpy)

CH4 VOC

Transmission

Reciprocating Compressors 651 18 

Wet Seal Centrifugal Compressors 0 0 

Dry Seal Centrifugal Compressors 39.4 1.09 

Storage

Reciprocating Compressors 1,215 33.6 

Wet Seal Centrifugal Compressors 117 3.24 

Dry Seal Centrifugal Compressors 73.5 2.04 

8.4 Control Techniques 

8.4.1 Potential Control Techniques 

The potential control options reviewed for reducing emissions from reciprocating compressors 

include control techniques that limit the leaking of natural gas past the piston rod packing. This includes 

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

realignment of the piston rod. 

The replacement of the rod packing is a maintenance task performed on reciprocating 

compressors 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 

CH4 and VOC emissions. Therefore, this control technique was determined to be an appropriate option 

for reciprocating compressors. 
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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.106 Rods wear “out-ofround” 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. This analysis assumes operators will choose, at their discretion, when to replace 

the rod and hence, does not consider this control technique to be a practical control option for 

reciprocating compressors. A summary of these techniques are presented in the following sections. 

Potential control options to reduce emissions from centrifugal compressors include control 

techniques that limit the leaking of natural gas across the rotating shaft, or capture and destruction of the 

emissions using a combustion device. A summary of these techniques are presented in the following 

sections. 

One control technique for limiting or reducing the emission from the rotating shaft of a 

centrifugal compressor is a mechanical dry seal system. This control technique uses rings to prevent the 

escape of natural gas across the rotating shaft. This control technique was determined to be a viable 

option for reducing emission from centrifugal compressors. 

For centrifugal compressors equipped with wet seals, a combustion device was considered to be a 

reasonable option for reducing emissions from centrifugal compressors. Centrifugal compressors require 

seals around the rotating shaft to prevent natural gas from escaping where the shaft exits the compressor 

casing. “Beam” type compressors have two seals, one on each end of the compressor, while “over-hung” 

compressors have a seal on only the “inboard” (motor end) side. These seals use oil, which is circulated 

under high pressure between three rings around the compressor shaft, forming a barrier against the 

compressed gas leakage. The center ring is attached to the rotating shaft, while the two rings on each 

side are stationary in the seal housing, pressed against a thin film of oil flowing between the rings to both 

lubricate and act as a leak barrier. The seal also includes “O-ring” rubber seals, which prevent leakage 

around the stationary rings. The oil barrier allows some gas to escape from the seal, but considerably 

more gas is entrained and absorbed in the oil under the high pressures at the “inboard” (compressor side) 

                                                            

106 U.S. EPA. Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR. 

Washington DC. 2006. 
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seal oil/gas interface, thus contaminating the seal oil. Seal oil is purged of the absorbed gas (using 

heaters, flash tanks, and degassing techniques) and recirculated back to the seal. As a control measure, 

the recovered gas would then be sent to a combustion device. 

8.4.2 Reciprocating Compressor Rod Packing Replacement 

8.4.2.1 Description 

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 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 gas will escape. Periodically replacing the packing rings ensures 

the correct fit is maintained between packing rings and the rod. 

8.4.2.2 Emissions Reduction Potential 

As discussed above, regular replacement of the reciprocating compressor rod packing can reduce 

the leaking of natural gas across the piston rod. The emission reductions for the transmission and storage 

segment were calculated by multiplying the number of new reciprocating compressors in each segment 

by the difference between the average rod packing emission factors (as presented in Table 8-2) and the 

average emission factor for newly installed rod packing. This calculation, shown in the Equation 1 

below, was performed for the transmission and storage segment. 

Equation 1   6

&

10

    8760  Comp E E C O R G B New

PTS

New

PTS

where: 

RPTS = Potential CH4 emission reductions from transmission or storage compressors switching from wet 

seals to dry seals, in million cubic feet per year (MMcf/year). 

Comp = Number of new transmission or storage compressors. 

EG&B = Methane emission factor for transmission or storage compressors in Table 8-2, in cubic feet per hour 

per cylinder. 

ENew=Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per hour per 

cylinder107 for this analysis.

C = Average number of cylinders for transmission or storage compressors in Table 8-2. 

O = Percent of time during the calendar year the average transmission or storage compressor is in the 

operating and standby pressurized modes, 79.1%, 67.5% respectively. 

8760 = Number of days in a year. 

106

 = Number of cubic feet in a million cubic feet. 

                                                            

107 Ibid. 
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A summary of the potential emission reductions for reciprocating compressor rod packing 

replacement in the transmission and storage segment is presented in Table 8-6. The emissions of VOC 

were estimated using the CH4 emissions calculated above and the CH4-to-VOC- ratio developed for each 

of the segments in the gas composition analysis conducted for the NSPS.108

Table 8-6. Estimated Annual Reciprocating Compressor Emission Reductions from Replacing Rod 

Packing 

Compressor 

Location

Number of New 

Sources Per 

Year

Individual Compressor Emission 

Reductions 

(tons/compressor-year)

Nationwide Emission 

Reductions 

(tpy)

CH4 VOC CH4 VOC

Transmission 24 21.7 0.600 520 14.4 

Storage 43 21.8 0.604 939 26. 

8.4.2.3 Cost Impacts

Costs for the replacement of reciprocating compressor rod packing were obtained from a Natural 

Gas STAR Lessons Learned document109 which estimated the cost to replace the packing rings to be 

$1,712 per cylinder. It was assumed that rod packing replacement would occur during planned shutdowns 

and maintenance and therefore, no travel costs will be incurred for implementing the rod packing 

replacement program. In addition, no costs were included for monitoring because the rod packing 

placement is based on number of hours that the compressor operates, or the time since the last 

replacement. The replacement of rod packing for reciprocating compressors occurs on average every four 

years based on industry information from the Natural Gas STAR Program.110 The cost impacts are based 

on the replacement of the rod packing 26,000 hours that the reciprocating compressor operates in the 

pressurized mode. 

For the 2012 NSPS, the number of hours used for the cost impacts was determined using a 

weighted average of the annual percentage that the reciprocating compressors are pressurized for all of the 

new sources. This percentage of hours is, on average, the number of hours per year a reciprocating 

compressor is pressurized and was used as the basis for the cost evaluation as it was determined to be the 

best available industry-wide percent pressurized value. The weighted average percentage was calculated to 

be 98.9 percent. This percentage was multiplied by the total number of hours in 3 years to obtain a value 

                                                            

108 See footnote 5. 109 See footnote 101. 110 Ibid.
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of 26,000 hours. This calculates to an average of 3.8 years for transmission compressors and 4.4 years for 

storage compressors using the operating factors in Table 8-2. The calculated years were assumed to be the 

equipment life of the compressor rod packing and were used to calculate the capital recovery factor for 

each of the segments. Assuming an interest rate of 7 percent, the capital recovery factors were calculated 

to be 0.3122 for transmission compressors and 0.2720 for storage compressors. The capital costs were 

calculated using the average rod packing cost of $1,712 and the average number of cylinders per segment 

as presented in Table 8-2. The annual costs were calculated using the capital cost and the capital recovery 

factors. 

The cost per ton of emissions reduced was then calculated in two ways. The first method, or singlepollutant approach, allocated all of the costs to each pollutant separately. The second method, or multipollutant approach, allocated costs among the pollutants that a given technology reduced (i.e., CH4 and 

VOC). The multi-pollutant approach was based on estimates of the percentage reduction expected for each 

pollutant. A summary of the capital and annual costs for the transmission and storage segment is shown in 

Table 8-7. 

There is monetary savings associated with the amount of gas saved with reciprocating compressor 

rod packing replacement, however, these savings were not included in the cost estimates for the 

transmission and storage segment because it is assumed that the owner/operator of the compressor 

generally is not the owner of the natural gas that is compressed at their compressor stations.

Table 8-7. Cost of Control for Reciprocating Compressor Rod Packing Replacement ($2012) 

Compressor 

Location

Capital Cost 

($)

Annual Cost 

($/yr) 

Cost of Control 

Single-Pollutant 

($/ton)

Cost of Control 

Multi-Pollutant Method 

($/ton) 

CH4 VOC CH4 VOC 

Transmission $5,650 $1,748 $81 $2,910 $40 $1,455 

Storage $7,705 $2,077 $95 $3,434 $48 $1,717 

8.4.2.4 Secondary Impacts 

The reciprocating compressor rod packing replacement is an option that prevents the escape of 

natural gas from the piston rod. No wastes should be created, no wastewater generated, and no 

maintenance of electrical systems and therefore, no travel costs will be incurred for implementing the 

rod packing replacement program. In addition, no costs were included for monitoring because the rod 

packing is replaced based on operating hours or time since the last replacement. 
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8.4.3 Centrifugal Compressor Dry Seals 

8.4.3.1 Description

Centrifugal compressor dry seals operate mechanically under the opposing force created by 

hydrodynamic grooves and springs. 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 gas has only one pathway to leak down the shaft, and that is between the 

rotating and stationary rings. This gas is pumped between the rings by grooves in the rotating ring. The 

opposing force of high-pressure gas pumped between the rings and springs trying to push the rings 

together creates a very thin gap between the rings through which little 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. 

Dry seals substantially reduce gas emissions compared to wet seals. At the same time, they 

significantly reduce operating costs and enhance compressor efficiency compared to wet seals. Economic 

and environmental benefits of dry seals include: 

 Gas Leak Rates. During normal operation, dry seals leak at a rate of 6 scfm CH4 per 

compressor.111 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 re-circulated is usually vented to the atmosphere, bringing the total leakage 

rate for tandem wet seals to 47.7 scfm CH4 per compressor.112, 113

 Mechanically Simpler. Dry seal systems do not require additional oil circulation components and 

treatment facilities. 

 Reduced Power Consumption. Because dry seals have no accessory oil circulation pumps and 

systems, they avoid “parasitic” equipment power losses. Wet seal systems require 50 to 100 

kilowatt (kW) per hour, while dry seal systems need about 5 kW of power per hour. 

 Improved Reliability. The highest percentage of downtime for a compressor using wet seals is 

due to seal system problems. Dry seals have fewer ancillary components, which translates into 

                                                            

111 U.S. EPA. Lessons Learned: Replacing Wet Seals with Dry Seals in Centrifugal Compressors. October 2006. Available at 

http://epa.gov/gasstar/documents/ll_wetseals.pdf. 112 “Methane’s Role in Promoting Sustainable Development in the Oil and Natural Gas Industry”. US EPA, ICF International, 

PEMEX, EnCana Oil & Gas, Hy-Bon Engineering, Pluspetrol, Gazprom, VNIIGAZ. World Gas Conference 10/2009. Available 

at http://www.epa.gov/gasstar/documents/best_paper_award.pdf 113 See footnote 6.
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higher overall reliability and less compressor downtime. 

 Lower Maintenance. Dry seal systems have lower maintenance costs than wet seals because 

they do not have moving parts associated with oil circulation (e.g., pumps, control valves, relief 

valves, and the seal oil cost itself). 

 Elimination of Oil Leakage from Wet Seals. Substituting dry seals for wet seals eliminates seal 

oil leakage into the pipeline, thus avoiding contamination of the gas and degradation of the 

pipeline. 

8.4.3.2 Emissions Reduction Potential 

The emissions reductions of the dry seal compressors was calculated by subtracting the dry seal 

emissions from the emissions from a centrifugal compressor equipped with wet seals. The centrifugal 

compressor emission factors in Table 8-2 were used in combination with an operating factor of 30 

percent for transmission centrifugal compressors and 22.4 percent for storage centrifugal compressors. 

The operating factors are used to account for the percent of time in a year that a compressor is in the 

operating mode. The operating factors are based on data from the GHG Inventory.114 The wet seals 

emission factor is an average of 48 different wet seal centrifugal compressors. The dry seal emission 

factor is based on information from the Natural Gas STAR Program.115 A summary of the emission 

reduction from the replacement of wet seals with dry seals is shown in Table 8-8.

Table 8-8. Estimated Annual Centrifugal Compressor Emission Reductions from Replacing Wet 

Seals with Dry Seals 

Compressor Location

Number of 

New Sources 

Per Year

Individual Compressor Emission 

Reductions 

(ton/compressor-year)

Nationwide Emission Reductions 

(tpy)

CH4 VOC CH4 VOC

Transmission 0 137 3.79 0 0 

Storage 1 102 2.83 102 2.83 

8.4.3.3 Cost Impacts 

The price difference between a brand new dry seal and brand new wet seal centrifugal 

compressor is insignificant relative to the cost for the entire compressor. General Electric (GE) stated 

that a natural gas transmission pipeline centrifugal compressor with dry seals cost between $50,000 and 

$100,000 more than the same centrifugal compressor with wet seals. However, this price difference is 

                                                            

114 See footnote 6. 115 U.S. EPA. Lessons Learned: Replacing Wet Seals with Dry Seals in Centrifugal Compressors. Natural Gas STAR. 2006.  
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only about 1 to 3 percent of the total cost of the compressor. The price of a brand new natural gas 

transmission pipeline centrifugal compressor between 3,000 and 5,000 horsepower runs between $2 

million to $5 million depending on the number of stages, desired pressure ratio, and gas throughput. The 

larger the compressor, the less significant the price difference is between dry seals and wet seals. This 

analysis assumes the additional capital cost for a dry seal compressor is $75,000 ($79,268 in 2012 

dollars). The annual cost was calculated as the capital recovery of this capital cost assuming a 20-year 

equipment life and 7 percent interest which came to $7,482 per compressor. The Natural Gas STAR 

Program estimated that the annual operation and maintenance savings from the installation of dry seal 

compressor is $88,300 in comparison to wet seal compressor. The cost per ton of emissions reduced was 

then calculated in two ways. The single-pollutant method allocated all of the costs to each pollutant 

separately. The multi-pollutant method prorated costs among the pollutants that a given technology 

reduced (i.e., CH4 and VOC). The multi-pollutant method was based on estimates of the percentage 

reduction expected for each pollutant. A summary of the capital and annual costs for dry seals is 

presented in Table 8-9 along with the CH4 and VOC cost of control for the dry seal compressor option. 

There is no gas savings cost benefits for transmission and storage facilities, because it is assumed the 

owners of the compressor station do not own the natural gas that is compressed at the station.

Table 8-9. Cost of Reductions for Centrifugal Compressor Using Dry Seal Compressors ($2012) 

Compressor 

Location 

Capital 

Cost 

($) 

Annual Cost Per 

Compressor 

($/compressor-year) 

CH4 Cost of Control 

($/ton) 

VOC Cost of Control 

($/ton) 

without 

savings 

with O&M 

savings 

without 

savings 

with O&M 

savings 

without 

savings 

with O&M 

savings 

Single-Pollutant

Transmission $79,268 $7,482 -$85,843 $55 -$627 $1,974 -$22,642 

Storage $79,268 $7,482 -$85,843 $73 -$840 $2,643 -$30,324 

Multi-Pollutant Method 

Transmission $79,268 $7,482 -$85,843 $27 -$314 $987 -$11,321 

Storage $79,268 $7,482 -$85,843 $37 -$420 $1,322 -$15,162 

8.4.3.4 Secondary Impacts 

Dry seals for centrifugal compressors are an option that prevents the escape of natural gas across 

the rotating compressor shaft. No wastes should be created, no wastewater generated, and no electricity 

needed. Therefore, there are no secondary impacts expected due to the installation of dry seals on 

centrifugal compressors. 
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8.4.4 Centrifugal Compressor Wet Seals Routed to a Combustion Device 

8.4.4.1 Description 

Another control option used to reduce pollutant emissions from centrifugal compressors equipped 

with wet seals is to route the emissions to a combustion device or capture the emissions and route them to 

a fuel system. A wet seal system uses oil that is circulated under high pressure between three rings 

around the compressor shaft, forming a barrier against the compressed gas. The center ring is attached to 

the rotating shaft, while the two rings on each side are stationary in the seal housing, pressed against a 

thin film of oil flowing between the rings to both lubricate and act as a leak barrier. Compressed gas 

becomes absorbed and entrained in the fluid barrier and is removed using a heater, flash tank, or other 

degassing technique so that the oil can be recirculated back to the wet seal. The removed gas is either 

combusted or released to the atmosphere. The control technique investigated in this section is the use of 

wet seals with the removed gas sent to a combustion device or other process. 

8.4.4.2 Emissions Reduction Potential 

Combustion devices have been used in the oil and natural gas industry to combust gas streams 

that have VOC and HAP. A combustion device typically achieves 95 percent reduction of these 

compounds when operated according to the manufacturer instructions. For this analysis, it was assumed 

that the entrained gas from the seal oil that is removed in the degassing process would be directed to a 

combustion device that achieves 95 percent reduction of CH4, VOC, and HAP. The wet seal emissions in 

Table 8-5 were used along with the control efficiency to calculate the emissions reductions from this 

option. A summary of the emission reductions is presented in Table 8-10. 
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Table 8-10. Estimated Annual Centrifugal Compressor Emission Reductions from Wet Seals Routed 

to a Combustion Device 

Compressor Station

Number of 

New Sources 

Per Year

Individual Compressor 

Emission Reductions 

 (tons/compressor-year)

Nationwide Emission 

Reductions 

(tpy)

CH4 VOC CH4 VOC

Transmission 0 149 4.12 0 0 

Storage 1 111 3.08 111 3.08 

8.4.4.3 Cost Impacts 

The capital and annual cost of the combustion device (an enclosed flare for the analysis) was 

calculated using the methodology in the EPA Control Cost Manual.116 The heat content of the gas stream 

was calculated using information from the gas composition memorandum.117 A summary of the capital 

and annual costs for wet seals routed to a flare is presented in Table 8-11. The cost per ton of emissions 

reduced was then calculated in two ways. The single-pollutant approach allocated all of the costs to each 

pollutant separately. The multi-pollutant approach allocated costs among the pollutants that a given 

technology reduced (i.e., CH4 and VOC). This allocation was based on estimates of the percentage 

reduction expected for each pollutant. The CH4 and VOC cost of control for the wet seals routed to a 

combustion device option is also shown in Table 8-11. There is no cost savings estimated for this option 

because the recovered gas is combusted. 

Table 8-11. Cost of Control for Centrifugal Compressor Wet Seal Emission Routed to a Combustion 

Device 

Compressor 

Location

Capital Cost 

($)

Annual Cost per 

Compressor 

($/compressor-year) 

Cost of Control 

New CD 

($/ton)

Cost of Control 

Existing CD 

($/ton)

New CD Existing CD New CD Existing CD CH4 VOC CH4 VOC 

Single-Pollutant 

Transmission $71,783 $23,252 $114,146 $3,311 $767 $27,705 $22 $804 

Storage $71,783 $23,252 $114,146 $3,311 $1,028 $37,105 $30 $1,076 

Multi-Pollutant Method 

Transmission $71,783 $23,252 $114,146 $3,311 $384 $13,853 $11 $402 

Storage $71,783 $23,252 $114,146 $3,311 $514 $18,553 $15 $538 

CD = Control Device 

                                                            

116 EPA Air Pollution Control Cost Manual - Sixth Edition, (EPA 452/B-02-001). 117 See footnote 5.
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8.4.4.4 Secondary Impacts 

There are secondary impacts with the option to use wet seals with a combustion device. The 

combustion of the recovered gas creates secondary emissions of hydrocarbons, (NOX, CO2, and CO 

emissions. A summary of the estimated secondary emission are presented in Table 8-12. No other wastes 

should be created or wastewater generated 

Table 8-12. Secondary Impacts from Wet Seal Emissions Routed to a Combustion Device 

a. Based on combustion of natural gas stream and AP-42 Total Hydrocarbons emission factors for industrial flares. 

b. Based on combustion of natural gas stream and AP-42 Carbon Monoxide emission factors for industrial flares. 

c. Based on combustion of natural gas stream and 40 CFR Part 98, subpart Y, Equation Y-2. 

d. Based on combustion of natural gas stream and AP-42 Nitrogen Oxides emission factors for industrial flares. 

e. Based on combustion of natural gas stream and AP-42 Particulate Matter emission factors for industrial flares. 

Assumes a “lightly smoking” flare. 

8.5 Regulatory Options 

Subpart OOOO defines a reciprocating compressor is defined as a piece of equipment that 

increases the pressure of a process gas by positive displacement, employing linear movement of the 

driveshaft. A centrifugal compressor is defined as a piece of equipment that compresses a process gas by 

means of mechanical rotating vanes or impellers. Therefore these types of compressors would be subject 

to the NSPS at the time of installation. The following Regulatory options were evaluated: 

 Regulatory Option 1. Require replacement of the reciprocating compressor rod packing based 

on 26,000 hours of operation while the compressor is pressurized. 

 Regulatory Option 2. Require all centrifugal compressors to be equipped with dry seals. 

 Regulatory Option 3. Require centrifugal compressors equipped with a wet seal to route the 

recovered gas emissions to a combustion device. 

8.5.1 Evaluation of Regulatory Options 

The first regulatory option for replacement of the reciprocating compressor rod packing based on 

the number of hours that the compressor operates in the pressurized mode was described in Section 8.4.1. 

The CH4 and VOC cost of control for reciprocating compressors at transmission stations is $81 and 

$2,910 per ton, respectively. The CH4 and VOC cost of control for reciprocating compressors at storage 

Compressor 

Location 

Secondary Impacts from Wet Seals Routed to a Combustion Device 

(tpy) 

THCa COb CO2

c NOxd PMe

Transmission 0 0 0 0 0 

Storage 0.58 1.54 550 0.28 0.01 
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facilities is $95 and $3,434 per ton, respectively. Based on these cost of control values for CH4, 

Regulatory Option 1 was accepted for the transmission and storage segment. 

The second regulatory option would require all centrifugal compressors to be equipped with dry 

seals. As presented in Section 8.4.2, dry seals are effective at reducing emissions from the rotating shaft 

of a centrifugal compressor. Dry seals also reduce operation and maintenance costs in comparison to wet 

seals. The CH4 and VOC cost of emissions reductions for dry seals compressors was calculated to be 

$55/ton and $1,974/ton respectively for centrifugal compressors located at transmission facilities, not 

including the savings from operation and maintenance costs. When those savings were considered the 

CH4 and VOC cost of control was calculated to be -$627/ton and -$22,642/ton. The CH4 and VOC cost 

of control for dry seal compressors was calculated to be $73/ton and $2,643/ton respectively for 

centrifugal compressors located at storage facilities, not including the savings from operation and 

maintenance costs. When those savings were considered the CH4 and VOC cost of control was calculated 

to be -$840/ton and -$30,324/ton. However, commenters on the 2011 Oil and Natural Gas NSPS noted 

that are certain situations where installing a dry seal system is not feasible, such as where gas 

composition is inadequate and in retrofits of some existing compressors due to housing design or 

operational requirements. Therefore, Regulatory Option 2 was rejected as a regulatory option for 

centrifugal compressors located at transmission or storage facilities. 

The third regulatory option would allow the use of wet seals if the recovered gas emissions were 

routed to a combustion device or another useful process. The CH4 and VOC cost of control for routing 

emissions from a wet seal system to a combustion device was calculated to be $767/ton and $27,705/ton 

respectively for centrifugal compressors located at transmission facilities. The CH4 and VOC cost of 

control for routing emissions from a wet seal system to a combustion device was calculated to be 

$1,028/ton and $37,105/ton respectively for centrifugal compressors located at transmission facilities. 

However, facilities may already have a combustion device operating at the facility or would route the 

captured gas back to a useful process rather than flaring it. Those facilities would not incur the additional 

capital cost and operation and maintenance costs of the flare. For those facilities the CH4 and VOC cost 

of control were calculated to be $22/ton and $804/ton respectively for transmission facilities and $30/ton 

and $1,076/ton respectively for storage facilities. Based on these cost of control values, Regulatory 

Option 3 was accepted for the transmission and storage segment. 

8.5.2 Nationwide Impacts of Selected Regulatory Options 

Tables 8-13 and 8-14 summarize the impacts of the selected regulatory options by industry 
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segment. Regulatory Option 1 is estimated to affect 24 reciprocating compressors at transmission 

facilities and 43 reciprocating compressors at underground storage facilities I a typical year. The 

nationwide impacts for projected year 2020 are based on a typical year. The projected affected number of 

compressors for projected year 2025 is calculated as all compressors affected from 2020 through 2025. A 

summary of the capital and annual costs and emission reductions for this option is presented in Table 8-

13. 

Regulatory Option 2 is expected to affect 1 new wet-seal centrifugal compressor in the 

transmission and storage segment (specifically at a storage facility). The number of affected centrifugal 

compressors is low because the historical rate of growth in the overall number of wet seal centrifugal 

compressors in the segment has been low, indicating few new compressors are being installed. In 

addition, most new centrifugal compressors are expected to use dry seals, which would not be affected 

facilities. A summary of the capital and annual costs and emission reductions for this option is presented 

in Table 8-14. A summary of the nationwide secondary combustion-related emissions from Option 2 are 

summarized in Table 8-15. 
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Table 8-13. Nationwide Cost Impacts for Regulatory Option 1 

Compressor 

Location 

Number of New Sources 

Per Year 

Nationwide Emission Reductions 

(tpy) Total Nationwide Co

CH4 VOC Capital Cost ($) Ann

Base Year 2012 and Projected Year 2020 

Transmission 24 520 14.4 $135,606 Storage 43 939 26 $331,310 

Projected Year 2025 

Transmission 144 3,122 87 $813,636 $

Storage 258 5,634 156 $1,987,860 $

Table 8-14. Nationwide Cost Impacts for Regulatory Option 3 

Compressor 

Location

Number of 

New Sources 

Per Year

Nationwide Emission 

Reductions 

(tpy)

Nationwide Costs 

CH4 VOC

Capital Cost 

New CDa 

($) 

Capital Cost 

Existing CDb 

($) 

Annual Cost 

New CDa 

($/year) 

An

Exi

(

Base Year 2012 and Projected Year 2020 

Transmission 0 0 0 $0 $0 $0 Storage 1 111 3 71,783 $23,252 $114,146 

Projected Year 2025 

Transmission 0 0 0 $0 $0 $0 Storage 6 666 19 $430,697 $139,512.28 $684,874 

a. CD = Combustion Device Cost is based installation of a full system of control using a combustion device. 

b. Cost is based on routing compressor to an existing combustion device. 
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Table 8-15. Nationwide Secondary Impacts from Compressor Emissions Routed to a Combustion 

Device 

a. Based on combustion of natural gas stream and AP-42 Total Hydrocarbons emission factors for industrial flares. 

b. Based on combustion of natural gas stream and AP-42 Carbon Monoxide emission factors for industrial flares. 

c. Based on combustion of natural gas stream and 40 CFR Part 98, subpart Y, Equation Y-2. 

d. Based on combustion of natural gas stream and AP-42 Nitrogen Oxides emission factors for industrial flares. 

e. Based on combustion of natural gas stream and AP-42 Particulate Matter emission factors for industrial flares. 

Assumes a “lightly smoking” flare. 

 

Compressor 

Location 

(tpy) 

THCa COb CO2

c NOxd PMe

Projected Year 2020 

Storage 0.58 1.54 550 0.28 0.01 

Projected Year 2025 

Production 3.48 9.24 3,300 1.68 0.06 
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9.0 OTHER POTENTIAL IMPACTS 

The following sections describe impacts potentially realized as a result of the implementation of 

regulatory options discussed in the sections above. Specifically, many of the options discussed have 

potential to realize natural gas savings based on the capture of natural gas that would have otherwise been 

emitted or combusted. This natural gas savings can result in monetary savings to the owner or operator 

which can offset costs incurred by control requirements. Although the NSPS does not directly regulate 

HAP, HAP emission are reduced as a result of the reductions in the emissions of natural gas. Finally, since 

CH4 is known to contribute to global warming, reducing CH4 emissions has the net effect of reducing 

contribution of the oil and gas industry to global warming. Consistent with the GHG Inventory, the global 

warming potential is discussed here as CO2e of CH4. 

9.1 Natural Gas Savings 

A potential benefit of emissions reductions for the affected facilities under the NSPS is the gas 

savings realized in the process of capturing gas that would have otherwise been vented or combusted. 

With respect to the regulatory options presented above, there are several opportunities for gas savings to 

be realized, as noted below: 

 For oil well completions, with implementation of a REC we estimated that 899 Mcf of natural gas 

is recovered during the average 3-day completion event. 

 For equipment leaks, the semiannual frequency of implementation of an OGI monitoring plan and 

repair of leaks found we estimate that the average annual gas saved would be 38 Mcf for oil wells, 

158 Mcf for gas wells, 1,222 Mcf for gathering and boosting stations, 1,937 Mcf for transmission 

stations, and 5,107 for storage facilities. 

 For pneumatic controllers, we estimate the use of low-bleed controllers instead of high-bleed 

controllers will save 147 Mcf of natural gas per year. 

 For reciprocating compressors, we estimate that the replacement of rod packing every 26,000 hours 

of operations (or every three years) will avoid the loss of, for each reciprocating compressor, 

1,122 Mcf per year for transmission facilities and 1,130 Mcf per year for storage facilities.118

 For centrifugal compressors, we estimate that the replacement of one wet seal compressor with a 

dry seal compressor will save 5,290 Mcf per year.119

                                                            

118 See footnote 4. 119 See footnote 4.
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Based on the above per unit natural gas savings and the new source activity counts anticipated for 

the projected years 2020 and 2025 for the affected facilities, we calculated the nationwide gas savings for 

each of the regulatory options discussed in the sections above for the projected years 2020 and 2025. Table 

9-1 presents the gas savings we estimate for these affected facilities. 

Table 9-1. Estimated Nationwide Natural Gas Savings for Selected Regulatory Options 

Affected Facility 

Number of Affected 

Facilities Subject to 

NSPSa

Volume of Gas 

Saved 

(MMcf) 

Value of Gas 

Saved 

($ million) 

Projected Year 2020 

Well Completions 

 Development Oil Wells 6,903 6,206 $24.8 

Equipment Leaks 

 Oil Well Site 16,562 629 $2.5 

 Gas Well Site 5,518 872 $3.5 

 Gathering 259 316 $1.3 

 Transmission 6 12 $0.0 

 Storage 15 77 $0.3 

Pneumatic Controllers 210 66,060 $0.3 

Pneumatic Pumps 2,960 31 $0.1 

Reciprocating Compressors - Transmission 24 0 0.0 

Reciprocating Compressors - Storage 43 27 $0.11 

Centrifugal Compressors - Storage 1 49 $0.19 

 Total Projected Year 2020 32,501 8,224 $33 

Projected Year 2025

Well Completions 

 Development Oil Wells 9,133 6,301,770 $25 

Equipment Leaks 

 Oil Well Site 100,175 3,807 $15.2 

 Gas Well Site 38,933 6,151 $24.6 

 Gathering 1,554 1,899 $7.6 

 Transmission 36 70 $0.3 

 Storage 90 460 $1.8 

Pneumatic Controllers 1,259 186 $0.7 

Pneumatic Pumps 17,760 0 0.0 

Reciprocating Compressors - Transmission 144 161,630 $0.65 

Reciprocating Compressors - Storage 258 289,587 $1.10 

Centrifugal Compressors - Storage 6 32 $0.13 

 Total Projected Year 2025 167,117 470,026 $77 

a. Reflects only the number of affected facilities subject to the NSPS that will have potential gas savings (not all sources will 

have potential for gas savings). 
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9.2 Reductions of HAP and CO2e 

A potential benefit of emissions reductions for the affected facilities under the NSPS is the 

reduction of HAP as a result of reduction of the gas that contains HAP. For the purposes of the NSPS, we 

estimate HAP emissions by applying a ratio to the CH4 emissions. The ratio used is based on gas 

composition analysis conducted for the NSPS.120 Because gas composition was determined to vary 

between industry segments and between the various affected facilities, different rations were used 

accordingly. Table 9-2 summarizes that HAP-to-CH4 ratios used for the various affected facilities in the 

various segments. 

Table 9-2. HAP-to-CH4 Ratios Used to Estimate HAP Emissions 

Segment Affected Facility HAP-to-CH4 

Ratio 

Production 

 

HF Oil Well Completions 

Equipment Leaks: 

 Oil Well sites 

 Gas Well Sites 

 Gathering and Boosting 

Pneumatic Pumps 

0.0001 

0.0105 

0.0105 

0.0105 

0.0105 

Transmission 

Equipment Leaks 

Pneumatic Pumps 

Pneumatic Controllers 

Reciprocating Compressors 

0.000822 

0.000822 

0.000822 

0.000822 

Storage 

Equipment Leaks 

Pneumatic Pumps 

Pneumatic Controllers 

Reciprocating Compressors 

Centrifugal Compressor 

0.000822 

0.000822 

0.000822 

0.000822 

0.000822 

Based on the CH4 emissions reductions estimated in the above sections for the respective affected 

facilities and regulatory options, we estimated the HAP emissions. Table 9-3 summarizes the HAP 

emissions calculated for each affected facility and regulatory option. 

Because CH4 is of concern for global warming effects, we also calculated the global warming 

potential expressed as CO2e for the CH4 reductions from the proposed regulatory options. For the purposes 

of this analysis, one ton of CH4 is equal to 25 tons of CO2e. We have converted the CO2e values to metric 

tonnes consistent with the presentation of CO2e in the GHG Inventory. Table 9-3 summarizes the global 

warming potential calculated for the proposed regulatory options. 

                                                            

120 See footnote 5. 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

201

Table 9-3. HAP and CO2e Reductions for Selected Regulatory Options 

Affected Facility 

Number of 

Sources Subject 

to NSPS 

Nationwide Emission Reductions 

CH4 

(tpy) 

VOC 

(tpy) 

HAP 

(tpy) 

CO2e 

(MT/year) 

Projected Year 2020 

HF Oil Well Completions 

 All Oil Wells 14,677 135,516 113,481 13.6 3,073,453 

 Development Oil Wells 13,806 127,479 106,751 12.7 2,891,169 

 Exploratory/Delineation Oil Wells 870 8,037 6,730 0.8 182,285 

Equipment Leaks 

 Oil Well Site 16,562 10,807 3,004 113.5 245,099 

 Gas Well Site 5,518 15,029 4,178 157.8 340,852 

 Gathering & Boosting 259 5,461 1,518 57.3 123,853 

 Transmission 6 225 6 0.2 5,103 

 Storage 15 1,480 27 1.2 33,566 

Pneumatic Controllers 210 1,248 35 1.0 28,304 

Pneumatic Pumps 2,960 5,399 1,501 4.4 122,447 

Reciprocating Compressors 

 Transmission 24 520 14.4 0.4 11,802 

 Storage 43 939 26 0.8 21,294 

 Centrifugal Compressors -Storage 1 102 2.8 0.08 2,318 

Total Projected Year 2020 40,275 176,063 123,774 350 3,993,050 

Projected Year 2025 

HF Oil Well Completions 

 All Oil Wells 14,970 138,221 115,747 13.8 3,134,810 

 Development Oil Wells 13,803 127,452 106728 12.7 2,890,554 

 Exploratory/Delineation Oil Wells 1,166 10,770 9,019 1.1 244,256 

Equipment Leaks 

 Oil Well Site 100,175 65,365 18,170 686.3 1,482,453 

 Gas Well Site 38,933 106,036 29,475 1113.4 2,404,856 

 Gathering 1,554 32,767 9,108 344.1 743,143 

 Transmission 36 1,347 37 1.1 30,549 

 Storage 90 8,879 246 7.3 201,372 
Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

202

Affected Facility 

Number of 

Sources Subject 

to NSPS 

Nationwide Emission Reductions 

CH4 

(tpy) 

VOC 

(tpy) 

HAP 

(tpy) 

CO2e 

(MT/year) 

Pneumatic Controllers 1,260 7,488 210 6.2 169,825 

Pneumatic Pumps 17,760 32,395 9,004 26.6 734,706 

Reciprocating Compressors 

 Transmission 144 3,122 87 2.5 70,811 

 Storage 42 5,634 156 4.5 127,766 

Centrifugal Compressors 

 Storage 6 613 17 0.5 13,907 

Total Projected Year 2025 174,970 397,890 182,144 2,203 9,024,004