# 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 CarolinaProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

i 

### DISCLAIMER
This report has been reviewed by Environmental Protection Agency’s (EPA) Office of Air Quality Planning and Standards (OAQPS) a nd has been approved for publication. Mention of trade names or commercial products is not intended to constitu te endorsement or recommendation for use.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

ii 

### FOREWORD
This background technical support document (TSD) pr ovides information relevant to the proposal
of amendments to the New Source Performan ce Standards (NSPS) at 40 CFR 60, subpart OOOO for limiting greenhouse gases (GHG), specifically methane (CH 4 

### ), and volatile organic compounds (VOC)
emissions from the Oil and Natural Gas Source Ca tegory. The proposed amendments, which are being proposed as 40 CFR 60, subpart OOOOa, were developed according to s ection 111(b)(1)(B) of the Clean Air Act (CAA), which requires the EPA to review a nd revise, as appropriate, NSPS standards. The NSPS review allows the EPA to identify processes in the o il and natural source category that are not regulated under the current NSPS but may be a ppropriate to regulate under NSPS based on new information. This would include processes that emit the current re gulated pollutants, VOC and sulfur dioxide (SO 2 

### ), 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 so urce category. Chapter 3 discusses the en tire NSPS review process undertaken for this review. Chapters 4-8 provide informati on on previously unregulated emissions sources and
revisions to standards for source s already regulated by the NSPS. E ach chapter describes the emission source, the estimated emissions (on average) from these sources, potential cont rol 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 fo r each emission source is provided. Finally, Chapter 9 summarizes other potential benefits such as natu ral gas savings and reductions of hazardous air pollutants (HAP) and global warming potential from CH 4



### .Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### TABLE OF CONTENTS
1.0 NEW SOURCE PERFORMA NCE BACKGROUND ................................................................................. 1 1.1 Statutory Authority

.............................................................................................................................. ....... 1
1.2 Regulatory History of Oil a nd 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 CO MPLETIONS AND RECOMPLETIONS ......... 12 4.1 Process Description

.............................................................................................................................. ..... 13
4.1.1 Oil Well Completions .......................................................................................................................... 13 4.1.2 Oil Well Recompletions ....................................................................................................................... 14 4.2 Emission Data and Emissions Factors .................................................................................................... 14
4.2.1 Summary of Major Studies and Emission Factors .............................................................................. 14 4.2.2 Representative Completion and Recompletion Emissions ................................................................... 17 4.3 Nationwide Emissions from New Sources ............................................................................................... 21
4.3.1 Determination of Number of Completions and Recompletions ........................................................... 21 4.3.2 Projected Number of Completions and Recompletions for 2020 and 2025 ........................................ 24
4.3.3 Emission Estimates

.............................................................................................................................. 25 4.4 Control Techniques

.............................................................................................................................. ..... 25
4.4.1 Potential Control Techniques .............................................................................................................. 25 4.4.2 Reduce Emission Completions and Recompletions ............................................................................. 26 4.4.3 Completion Combustion Devices ........................................................................................................ 30 4.5 Regulatory Options

.............................................................................................................................. ..... 35
4.5.1 Evaluation of Regulatory Options ....................................................................................................... 35 4.5.2 Nationwide Impacts of Regulatory Options ........................................................................................ 38 4.6 Comparison of Flowback Emissions Estimate Meth odology to Measured Emissions from UT-Austin – Allen et al. Study

.............................................................................................................................. ................ 44
5.0 FUGITIVE EMISSIONS STANDARDS .................................................................................................. ... 46 5.1 Fugitive Emissions Description ................................................................................................................ 46
5.2 Fugitive Emissions Data and Emissions Factors .................................................................................... 47
5.2.1 Summary of Major Studies and Emission Factors .............................................................................. 47 5.2.2 Model Plants

.............................................................................................................................. ......... 47 5.2.2.1 Oil and Gas Production ..................................................................................................................... 50Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

iv 5.3 Nationwide Emissions from New Sources ............................................................................................... 62
5.3.1 Overview of Approach ........................................................................................................................ 62 5.3.2 Activity Data

.............................................................................................................................. .......... 62 5.3.3 Emission Estimates

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

.............................................................................................................................. ..... 67
5.4.1 Potential Control Techniques ............................................................................................................. 67 5.4.2 Fugitive Emissions Detection and Correction with OGI ..................................................................... 68 5.4.3 Fugitive Emissions Detection and Correction with EPA Method 21 .................................................. 81 5.5 Regulatory Options

.............................................................................................................................. ... 100
5.5.1 Evaluation of Regulatory Options for Fugitive Emissions ................................................................ 101
5.5.2 Nationwide Impacts of Regulatory Options ...................................................................................... 108 6.0 PNEUMATIC CONTROLLERS ......................................................................................................... 130125 6.1 Process Description

........................................................................................................................... 130125
6.1.1 Pneumatic Controllers

................................................................................................................ 130125 6.2 Emissions Data and Information

..................................................................................................... 132127
6.2.1 Summary of Major Studies and Emission

................................................................................... 132127 6.2.2 Representative Pneumatic Device Emissions

.............................................................................. 133128 6.3 Nationwide Emissions from New Sources

....................................................................................... 135130
6.3.1 Approach

.............................................................................................................................. ....... 135130 6.3.2 Population of Controllers Installed Annually

............................................................................. 135130 6.3.3 Emission Estimates

...................................................................................................................... 136131 6.4 Control Techniques

........................................................................................................................... 136131
6.4.1 Low-Bleed Controller Emission Reduction Potential

................................................................. 140135 6.4.2 Emission Reduction Potential

..................................................................................................... 140135 6.4.3 Cost Impacts

.............................................................................................................................. .. 141136 6.4.4 Secondary Impacts

...................................................................................................................... 142137 6.5 Regulatory Options

........................................................................................................................... 142137
6.5.1 Evaluation of Regulatory Options

............................................................................................... 142137 6.5.2 Nationwide Impacts of Regulatory Options

................................................................................ 143138 7.0 PNEUMATIC PUMPS................................................................................................................

.......... 144139 7.1 Process Description

........................................................................................................................... 144139
7.1.1 Emissions Data and Information

................................................................................................. 146141 7.2 Nationwide Emissions from New Sources

....................................................................................... 148143
7.2.1 Approach

.............................................................................................................................. ....... 148143 7.2.2 Population of CIPs Installed Annually

........................................................................................ 148143 7.2.3 Emission Estimates

...................................................................................................................... 150145Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

v 7.3 Control Techniques

........................................................................................................................... 150145
7.3.1 Solar Pumps

.............................................................................................................................. .. 154149 7.3.2 Electric Pumps

............................................................................................................................ 155150 7.3.3 Instrument Air System

................................................................................................................. 156151 7.3.4 Install or Route Gas to Combustion Device

................................................................................ 162157 7.3.5 Install or Route Gas to VRU

........................................................................................................ 163158 7.4 Regulatory Options

........................................................................................................................... 164159
7.4.1 Evaluation of Regulatory Options

............................................................................................... 165160
7.4.2 Nationwide Impacts of Selected Regulatory Options

.................................................................. 177172 8.0 COMPRESSORS ...................................................................................................................

............... 179174 8.1 Process Description

........................................................................................................................... 179174
8.1.1 Reciprocating Compressors

........................................................................................................ 179174
8.1.2 Centrifugal Compressors

............................................................................................................ 179174 8.2 Emissions Data and Emissions Factors

........................................................................................... 180175
8.2.1 Summary of Major Studies and Emissions Factors

..................................................................... 180175 8.2.2 Representative Reciprocating and Centrifugal Compressor Emissions

...................................... 181176 8.3 Nationwide Emissions from New Sources

....................................................................................... 183178
8.3.1 Overview of Approach

................................................................................................................. 183178 8.3.2 Activity Data for Compressors in Transmission and Storage

..................................................... 183178 8.3.3 Emission Estimates

...................................................................................................................... 184179 8.4 Control Techniques

........................................................................................................................... 184179
8.4.1 Potential Control Techniques

...................................................................................................... 184179 8.4.2 Reciprocating Compressor Rod Packing Replacement

............................................................... 186181 8.4.3 Centrifugal Compressor Dry Seals

............................................................................................. 189184 8.4.4 Centrifugal Compressor Wet Seals Routed to a Combustion Device

.......................................... 192187 8.5 Regulatory Options

........................................................................................................................... 194189
8.5.1 Evaluation of Regulatory Options

............................................................................................... 194189
8.5.2 Nationwide Impacts of Selected Regulatory Options

.................................................................. 195190 9.0 OTHER POTENTIAL BENEFICIAL IMPACTS ............................................................................. 199194 9.1 Natural Gas Savings

......................................................................................................................... 199194
9.2 Reductions of HAP and CO 2 e

........................................................................................................... 201196Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### LIST OF TABLES Table 4-1. Major Studies Reviewed Emissions and Activity Data ................................................................. ............ 15 Table 4-2. Uncontrolled Emissions Estimates from Re presentative Oil Well Completion or Recompletion ............. 21 Table 4-3. Estimated Number of Total Oil Well Comple tions and Recompletions for a Representative Year (2012)

.............................................................................................................................. ....................................................... 24 Table 4-4. Estimated Number of Total Oil Well Comple tions and Recompletions for 2012, 2020 and 2025 ............ 24 Table 4-5. Nationwide Baseline Emissions for 2012, 2020 and 2025 from Hydraulically Fractured Oil Well Completions and Recompletions ................................................................................................. ................................ 25 Table 4-6. Reduced Emission Completion and Recompleti on Emission Reductions and Cost Impacts Summary .... 34 Table 4-7. Emission Factors from Flare Opera tions from AP-42 Guidelines Table 13.4-1 ........................................ 3 5 Table 4-8. Nationwide Emission and Cost Analysis of Regulatory Option ......................................................... ....... 40 Table 4-9. Nationwide Secondary Impacts of Select ed Regulatory Options for Projected Year 2020 ................... 4243 Table 4-10. Nationwide Secondary Impacts of Selected Regulatory Options for Projected Year 2025 ................. 4344 Table 4-11. Comparison of Flowback Emissions Estimate Methodology to Measured Emissions from the UT Austin - Allen et al. Study ..........................................................................................................

......................................... 4546

Table 5

‐ 1. Major Studies Reviewed for Emissions and Activity Data

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

..................................................................... 52 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)

................................. 52 Table 5-4. Average Fugitive Emissions Component C ount for Gas Production Well Site Model Plant .................... 58 Table 5-5. Average Fugitive Emissions Component C ount for Oil Production Well Site Model Plant ..................... 58 Table 5-6. Oil and Gas Production Oper ations Average Emissions Factors ........................................................ ....... 59 Table 5-7. Estimated Fugitive Emission Estimate fo r Natural Gas Production Well Site Model Plant ...................... 59 Table 5-8. Estimated Fugitive Emission Estimate for Oil Production Well Site Model Plant .................................... 5 9 Table 5-9. Average Fugitive Emissions Component Count for Gathering and Boosting Station Model Plant .......... 60 Table 5-10. Estimated Fugitive Emission Estimate Gathering and Boosting Station Model Plant ............................ 60 Table 5-11. Estimated Fugitive Emission Estimate for Oil and Natural Gas Transmission and Storage Model Plant 61 Table 5-12. Nationwide Baseline Emissions for Sources Subj ect to NSPS Monitoring and Repair Plans in 2020 and 2025 .......................................................................................................................... ................................................... 66 Table 5-13. Nationwide Emission Reductions for OGI Monito ring and Repair Plan Options for 2020 and 2025 ..... 71 Table 5-14. Summary of the Model Plant Cost of Control for the Annual OGI Monitoring Option - ....................... 75 Table 5-15. Summary of the Model Plant Cost of Co ntrol for the Semiannual OGI Monitoring Option -SinglePollutant ..................................................................................................................... ................................................. 76Table 5-16. Summary of the Model Plant Cost of Control for the Quarterly OGI Monitoring Option -SinglePollutant ..................................................................................................................... ................................................. 77 Table 5-17. Summary of the Model Plant Cost of Contro l for the Annual OGI Monitoring Option - Multi-Pollutant Method ........................................................................................................................ ................................................ 78 Table 5-18. Summary of the Model Plant Cost of Co ntrol for the Semiannual OGI Monitoring Option - MultiPollutant Method .............................................................................................................. ........................................... 79 Table 5-19. Summary of the Model Plant Cost of Co ntrol for the Quarterly OGI Monitoring Option - MultiPollutant Method .............................................................................................................. ........................................... 80 Table 5-20. Percent Reduction in Emissions for EPA Me thod 21 Monitoring and Repair Plan Options ................... 82 Table 5-21. Nationwide Emission Reductions for EPA Method 21 Monitoring and Repair Plan Options for 2020 and 2025 .......................................................................................................................... ................................................... 82Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

vii Table 5-22. Summary of the Model Plant Cost of Contro l for the Annual Method 21 Monitoring and Repair Plan Options Single-Pollutant ...................................................................................................... ....................................... 88 Table 5-23. Summary of the Model Plant Cost of Cont rol for the Semiannual Method 21 Monitoring and Repair Plan Options Single-Pollutant ................................................................................................. .................................... 90 Table 5-24. Summary of the Model Plant Cost of Control for the Quarterly Method 21 Monitoring and Repair Plan Options Single-Pollutant ...................................................................................................... ....................................... 92 Table 5-25. Summary of the Model Plant Cost of Contro l for the Annual Method 21 Monitoring and Repair Plan Options Multi-Pollutant ....................................................................................................... ........................................ 94 Table 5-26. Summary of the Model Plant Cost of Cont rol for the Semiannual Method 21 Monitoring and Repair Plan Options Multi-Pollutant .................................................................................................. .................................... 96 Table 5-27. Summary of the Model Plant Cost of Control for the Quarterly Method 21 Monitoring and Repair Plan Options Multi-Pollutant ....................................................................................................... ........................................ 98 Table 5-28. Summary of the Cost of Control for Su b Options of Option 1 Based on OGI Monitoring ................... 104 Table 5-29. Summary of the Cost of Control for Sub Op tions of Option 2 Based on Method 21 Monitoring and Three Repair Thresholds ....................................................................................................... .................................... 107 Table 5-30. Nationwide Emission and Cost Analysis fo r Regulatory Option 1a – Annual OGI Monition and Repair

.............................................................................................................................. ............................................... 115114 Table 5-31. Nationwide Emission and Cost Analysis fo r Regulatory Option 1b – Semiannual OGI Monitoring and Repair ........................................................................................................................

.......................................... 116115 Table 5-32. Nationwide Emission and Cost Analysis for Regulatory Option 2a – Annual Method 21 Monitoring and Repair ........................................................................................................................

.......................................... 117116 Table 5-33. Nationwide Emission and Cost Analysis for Regulatory Option 2b – Semiannual Method 21 Monitoring and Repair ....................................................................................................................

....................................... 120118 Table 5-34. Nationwide Emission and Cost Analysis fo r Regulatory Option 1a (Excluding Low-Producing Well Sites) ........................................................................................................................

............................................ 124121 Table 5-35. Nationwide Emission and Cost Analysis fo r Regulatory Option 1b (Excluding Low-Producing Well Sites) ........................................................................................................................

............................................ 125122 Table 5-36. Nationwide Emission and Cost Analysis fo r Regulatory Option 2a (Excluding Low-Producing Well Sites) ........................................................................................................................

............................................ 126123 Table 5-37. Nationwide Emission and Cost Analysis fo r Regulatory Option 2b (Excluding Low-Producing Well Sites) ........................................................................................................................

............................................ 128124
Table 6-1. Major Studies and Sources of Informati on Reviewed for Emissions and Activity Data ................... 132127 Table 6-2. Average Bleed Emission Estimates per Pneu matic Controller in the Natural Gas Transmission and Storage Segments ..............................................................................................................

.................................. 135130 Table 6-3. Estimated Number of Pneumatic Controllers Inst alled in a Typical Year in the Natural Gas Transmission and Storage Segments ..........................................................................................................

............................... 136131 Table 6-4. Nationwide Baseline Emissions from Representative Pneumatic Controller Installed in a Typical Year in Natural Gas Transmission and Storage Segments .................................................................................

.............. 136131 Table 6-5. Alternative Control Op tions for Pneumatic Controllers ..............................................................

...... 138133 Table 6-6. Estimated Annual Bleed Emission Reductions from Replacing a Representative High-Bleed Pneumatic Controller with a Representative Low-Bleed Pneumatic C ontroller in the Natural Gas Transmission and Storage Segments ......................................................................................................................

....................................... 140135 Table 6-7. Cost Projections for Repr esentative Pneumatic Controllers (2012) .................................................. 141136 Table 6-8. Cost-of Control for Low-Bleed Pneumatic Controllers versus High Bleed Pneumatics for the Transmission and Storage Segments (2012) ......................................................................................

................. 142137 Table 6-9. Nationwide Cost and Emission Reduction Impacts for Selected Regulatory Option ........................ 143138Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

viii Table 7-1. Major Studies Reviewed for Consid eration of Emissions and Activity Data .................................... 146141 Table 7-2. Average Bleed Emission Estimates Per Pneumatic Pump ................................................................

. 148143 Table 7-3. Estimated Count of Pneumatic Devices Installed in a Typical Year ................................................. 150145 Table 7-4. Nationwide Baseline Emissions from Representativ e Chemical Injection Pumps Installed in a Typical Year for the Oil and Natural Gas Industry .....................................................................................

..................... 150145 Table 7-5. Alternative Control Options for Gas-Driven Pumps ...................................................................

....... 152147 Table 7-6. Model Plant Characterization for Replacing Gas-Driven Pumps with Instrument Air System ......... 160155 Table 7-7. Cost of Compressor Replacemen t for Existing Instrument Air System ............................................ 161156 Table 7-8. Secondary Impacts from Pneumatic Pumps Routed to a Combustion Device .................................. 163158 Table 7-9. Cost of Control for Use of Instrument Air Systems at Natural Gas Processing Plants - Single-Pollutant

.............................................................................................................................. ............................................... 168163 Table 7-10. Cost of Control for Use of Instrument Air Systems at Natural Gas Processing Plants - Multi-pollutant Method ........................................................................................................................

........................................ 169164 Table 7-11. Cost of Control for Replacement with Sola r-Powered or Electric Pumps at Natural Gas Processing Plants - Single-pollutant .....................................................................................................

................................. 170165 Table 7-12. Cost of Control for Replacement with Sola r-Powered or Electric Pumps at Natural Gas Processing Plants - Multi-pollutant Method ...............................................................................................

........................... 170165 Table 7-13. Cost of Control for Routing Gas-Driven Pump Emissions to a VRU - Single-pollutant Method ... 171166 Table 7-14. Cost of Control for Routing Gas-Driven Pump Emissions to a VRU - Multi-Pollutant Method .... 172167 Table 7-15. Estimated Cost of Control for Emission Reduc tions from Routing Gas-Drive Pump Emissions to a New Combustion Device - Single-Pollutant Method ...................................................................................

............... 173168 Table 7-16. Estimated Cost of Control for Emission Reduc tions from Routing Gas-Drive Pump Emissions to a New Combustion Device - Multi-pollutant Method ....................................................................................

................ 174169 Table 7-17. Cost of Control for Routing Gas-Driven Pu mp Emissions to an Existing Combustion Device or VRU

.............................................................................................................................. ............................................... 175170 Table 7-18. Cost of Control for Routing Gas-Driven Pu mp Emissions to an Existing Combustion Device or VRU

.............................................................................................................................. ............................................... 176171 Table 7-19. Nationwide Impacts for Gas-Driv en Pumps for Selected Regulatory Option ................................. 178173 Table 7-20. Nationwide Secondary Impacts from Pneumatic Pumps Routed to a Combustion Device ............. 178173
Table 8-1. Major Studies Reviewed for Emissions and Activity Data .............................................................

... 180175 Table 8-2. Methane Emission Factors for R eciprocating and Centrifugal Compressors .................................... 182177 Table 8-3. Baseline Emission Estimates for R eciprocating and Centrifugal Compressors ................................. 182177 Table 8-4. Approximate Number of New Compressors in the Transmission and Storage Segments in a Typical Year

.............................................................................................................................. ............................................... 184179 Table 8-5. Nationwide Baseline Emissions for New Reciprocating and Centrifugal Compressors ................... 184179 Table 8-6. Estimated Annual Reciprocating Compress or Emission Reductions from Replacing Rod Packing . 187182 Table 8-7. Cost of Control for Reciprocating Compressor Rod Packing Replacement ($2012) ........................ 188183 Table 8-8. Estimated Annual Centrifugal Compressor Emission Reductions from Replacing Wet Seals with Dry Seals .........................................................................................................................

........................................... 190185 Table 8-9. Cost of Reductions for Centrifugal Compressor Using Dry Seal Compressors ($2012) ................... 191186 Table 8-10. Estimated Annual Centrifugal Compressor Emission Reductions from Wet Seals Routed to a Combustion Device .............................................................................................................

................................ 193188 Table 8-11. Cost of Control for Centrifugal Compressor Wet Seal Emission Routed to a Combustion Device 193188 Table 8-12. Secondary Impacts from Wet Seal Emissions Routed to a Combustion Device ............................. 194189 Table 8-13. Nationwide Cost Impacts for Regulatory Option 1 ...................................................................

...... 197192Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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

...... 197192 Table 8-15. Nationwide Secondary Impacts from Compressor Emissions Routed to a Combustion Device ..... 198193

Table 9-1. Estimated Nationwide Natural Gas Savings for Selected Regulatory Options .................................. 200195 Table 9-2. HAP-to-CH 4 Ratios Used to Esti mate HAP Emissions ..................................................................... 201196 Table 9-3. HAP and CO 2 e Reductions for Selected Regulatory Options ............................................................ 202197



### LIST OF FIGURES Figure 1. Oil and Natural Gas Operations ...................................................................................... ............................... 7Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

x 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 Tec hnology Advancement Corporation-WEST cfm cubic foot per minute CFR U.S. Code of Federal Regulations CH 4 methane CIPs chemical injection pumps CO carbon monoxide CO 2 carbon dioxide CO 2 e 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 H 2 S 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 ABBREVIATIONSProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

xi Acronyms/Abbreviations Description MMtCO 2 e million metric tons of CO 2 -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 NO x 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 SO 2 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 DivisionProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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## 1.0 NEW SOURCE PERFORMA NCE BACKGROUND
Standards of performance for new stationary sour ces are established under section 111 of the CAA (42 U.S.C. 7411), as amended in 1977. Section 111 di rects the Administrator to establish standards of performance for any category of ne w stationary sources of air pollution which “...causes or contributes significantly to air pollution which ma y reasonably be anticipated to en danger public health or welfare.” This TSD supports the proposed standards, which would control CH 4 

### , VOC and SO 2 

### emissions from the oil and natural gas source category.


### 1.1 Statutory Authority
Section 111 of the CAA requires the EPA Administrator to list categor ies of stationa ry 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 st andards for such source categories. A performance standard reflects the de gree of emission limitati on 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 source s, 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 ca tegories, determine the pollutants for which standards should be developed, identify the facilities within each source ca tegory 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 revi ew 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 current ly regulated for that source category.
In setting or revising a perfor mance standard, CAA section 111( a)(1) provides that performance standards are to “reflect the degr ee of emission limitation achievable th rough the applicati on of the BSER which (taking into account the co st of achieving such reduction a nd 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 identifiedProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

2 

### systems reduce air pollution in practi ce. For each control system identif ied, 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-bas ed standard or percent control), that reflects the BSER. Although such standards are based on the BS ER, the EPA may not prescribe a particular technology that must be used to comply w ith 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 el ect 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 producti on 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 addre ssed VOC emissions from leaking components at onshore natural gas processing plants (40 CFR pa rt 60, subpart KKK). On October 1, 1985 (50 FR 40158), a second NSPS was promulgated for th e source category that regulates SO 2 

### emissions from natural gas processing plants (40 CF R part 60, subpart LLL).

As a result of the review of these standa rds under CAA section 111(b)(1)(B), in 2012 the EPA published the final rule, “Standa rds 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 operatio ns not previously cove red, 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 re sults 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, w ith the exception of adding methane as a regulated pollutant for all affected facilities currently regula ted for VOC emissions. Standards are being proposed for currently unregulated VOC and CH 4 

### emission sources, namely hydr aulically fractured oil wellProposed 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 st orage segment. All of these amendments will be proposed under a new subpart, 40 CFR 60, subpart OOOOa. Th is proposal is a result of decisions based on the second and third steps of the re view which involves evaluating whet her 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 welfar e; and identifying and evaluating additional processes in the oil and natural gas sour ce category that are not covered under the existing NSPS but may be appropriate to de velop 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 SECT OR 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 processi ng, transmission and distribution of natural gas. Specifically for oil, the sector incl udes 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 sepa rated into four segments: (1) oil and natural gas production, (2) natural gas processi ng, (3) natural gas transmission and storage and (4) natural gas distribution. Each of these segmen ts 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 ex traction, production, recovery, lifting, stabilization, separation or trea tment of oil and/or natural ga s (including condensate). Production components may include, but are not limited to, wells a nd related casing head, tubing head and “Christmas tree” piping, as well as pumps, compressors, heater tr eaters, separators, storage vessels, pneumatic devices and dehydrators. Production operations also include we ll 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” wher e the wells are located, but also in clude 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 transpor t 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 th at house equipment to extract oil and gas from the ocean or lake floor and that process and/or transfer th e oil and gas to storage, transport vessels or onshore. Offshore production ca n also include secondar y 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 oi l can be the only product processed. Once the crude oil is separated from water and other impurities, it is esse ntially ready to be trans ported to the refinery via truck, railcar or pipeline. The oil re finery sector is considered separa tely from the oil and natural gasProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

5 

### sector. Therefore, at the point of custody transfer at the refiner y, the oil leaves the oil and natural gas sector and enters the pe troleum refining sector.
Natural gas is primarily made up of CH 4 

### . However, whether natural gas is associated gas from oil wells or non-associated gas from ga s or condensate wells, it commonly exists in mixtures with other hydrocarbons. These hydrocarbons are of ten 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 (H 2 

### S), carbon dioxide (CO 2 

### ), helium, nitrogen and other compounds.
Natural gas processing consists of separating cert ain hydrocarbons and fluids from the natural gas to produced “pipeline quality” dry natural gas. While some of the pr ocessing can be accomplished in the production segment, the complete processing of natu ral gas takes place in th e 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 condens ate separation, water removal, se paration of natural gas liquids,
sulfur and CO 2 

### removal, fractionation of natural gas liquid an d other processes, such as the capture of CO 2 

### separated from natural gas streams fo r delivery outside the facility.
The pipeline quality natural ga s leaves the processing segment and enters the transmission and storage segment. Pipelines in the natural gas transmi ssion and storage segment can be interstate pipelines that carry natural gas across state bou ndaries or intrastate pipelines, whic h transport the gas within a single state. While interstate pipelines ma y be of a larger diameter and opera ted 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 a nd 100 mile intervals along the pipe line. At a compressor station, the natural gas enters the station, where it is compre ssed by reciprocating or centrifugal compressors.
In addition to the pipelines and compressor sta tions, the natural gas transmission and storage segment includes aboveground and underground storag e facilities. Undergr ound 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, ther e are typically other processes, including compression, dehydrati on and flow measurement.
The distribution segment is the final step in deliv ering natural gas to customers. The natural gas enters the distribution segment from delivery points located on interstate and intrastate transmissionProposed 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 ci tygate. Natural gas distribution system s consist of thousands of miles of piping, including mains and service pipelines to th e customers. Distribution systems sometimes have compressor stations, although they are considerably smaller than transmission compressor stations.
Distribution systems include metering stations, wh ich allow distribution companies to monitor the natural gas in the system. Essentially, these mete ring stations measure the flow of gas and allow distribution companies to track natura l gas as it flows th rough the system.
Emissions can occur from a variety of proce sses and points throughout the oil and natural gas sector. Primarily, these emissions are organic compounds such as CH 4 

### , ethane, VOC and organic HAP. The most common organic HAP are n-hexane and BTEX compounds (benzene, tolu ene, ethylbenzene and xylenes). Hydrogen sulfide and SO 2 

### are emitted from production and processing operations that handle and treat sour gas. 1



### In addition, there are significant emissions associ ated with the reciprocating internal combustion engines and combustion turbines that power comp ressors throughout the oil and natural gas sector. However, emissions from internal combustion engine s and combustion turbines are covered by regulations specific to engines and turbines and, t hus, 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 lis t of source categories for which the EPA would promulgate standards of performa nce under section 111(b) of the CAA. One of those source categories was “crude oil and natural gas production.” The EPA inte rprets the "crude oil and natural gas production" source category listing as generally covering the oil and natural gas indus try. Specifically, with respect to the oil and natural gas industry, th e 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 s ources in the oil and natu ral gas source category. Unless otherwise noted, use of the te rm "gas" refers to natural gas.

1 Sour gas is defined as natural gas with a maximum H 2 S content of 0.25 gr/100 scf (4 parts per million by volume (ppmv)) along with the presence of CO 2.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document7Figure 1. Oil and Natural Gas Sector OperationsProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

8 

## 3.0 NEW SOURCE PERFORMANC E STANDARD REVIEW

Section 111(b)(1)(B) of the CAA requires the EPA to review and revise, if appropriate, NSPS standards. This review process co nsists of the following steps:

1. Evaluation of the existing NSPS to determine whet her they continue to re flect 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 pr omulgate 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 pollu tants as well as any additional pollutants identified in step two.
The following sections detail each of these steps.



### 3.1 Evaluation of the BS ER for Existing NSPS
During development of the NSPS amendments promulgated in 2012, BSER options for equipment leaks at natural gas pr ocessing plants (s ubpart KKK) and SO 2 

### emissions from sweetening units located at natural gas proces sing plants (subpart LLL) were ev aluated, which addressed all existing covered sources and pollutants in the prior NSPS. Therefore, this action in cludes no control technology
evaluations for those sources. In ad dition, 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 SO 2 

### 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 Standa rds for Hazardous Air Pollutants (NESHAP) that address air toxics from the oil and natural gas source category, spec ifically 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 CH 4 

### . The Inventory of U.S. Greenhouse Gas (GHG) Emissions and Sinks: 1990-
2013 estimates 2009 CH 4 

### emissions from Petroleum and Natura l Gas Systems (not including petroleumProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

9 

### refineries) to be 148 MMtCO 2 

### e (million metric tons of CO 2 

### -equivalents (CO 2 

### e)). 2 

### As a result, this proposed rule adds GHG emissions, specifically CH 4 

### , as a regulated pollutant for all currently covered
affected facilities in the NSPS as we ll as the additional affect ed facilities identified in these amendments.
The CH 4 

### emissions, reductions and cost of control evalua tions for affected facilities that are currently regulated under the rule were included in the tec hnical 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 informa tion in a memorandum titled "Summary of Reductions
of Methane Emissions and Methane Global Warmi ng Potential For 40 CFR 60 Subpart OOOO Affected
Facilities" available in the docket.
Significant emissions of nitrogen oxides (NO x 

### ) also occur at oil and natural gas sites due to the combustion of natural gas in reciprocating engi nes and combustion turbines used to drive the compressors that move natural ga s through the system, and from com bustion 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 cate gory and are not being addressed in
this action. The NO x 

### emissions from engines and turbines ar e 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 SO 2 

### and VOC emissions from ga s processing plants and VOC emissions from gas well completions and recompleti ons, pneumatic controllers, compressors and storage
vessels. The EPA has identified several additional sources of CH 4 

### and VOC that are included in the proposed standards. Specifically th e EPA is proposing to regulate CH 4 

### emissions from all affected facilities currently regulated unde r subpart OOOO that are regulated for VOC emissions. The EPA is also proposing to regulate CH 4 

### and VOC from hydraulically fr actured oil well completions and recompletions, compressors in the transmission and stor age 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 re mainder 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 developm ent of several NSPS related actions including the NSPS proposal in 2011 and final rule in 2012 a nd 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 pres entation, the following docum ents are consistently cited in the following sections:

 The TSD for the 2011 NSPS proposal, published in Jul y, 2011, will be referred to in this document
as "2011 NSPS TSD". 3



###  The supplemental TSD for the 2012 final NSPS sta ndards, published Apr il, 2012, will be referred
to in this document as "2012 NSPS STSD". 4



###  The gas composition memo that was developed du ring 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 develo pment 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 em ission 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 s ources are referred to as "GHGRP" and “GHG Inventory”. 6 

### Note that the GHGRP plans to release additi onal activity data in the fall of 2015 from its Petroleum and Natural Gas Systems source cat egory. These data cover oil and gas operations reporting to the GHGRP in 2011, 2012, 2013 and 2014. Thes e new activity data will be reviewed prior to finalization of this rule and incorporated into th is analysis if appropriate.

 

### All of the calculations supporting the analyses in this documen t 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

11Proposed 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 contro l 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 hi gh, and therefore, no requirements we re finalized for control of VOC emissions from oil well completions or recompleti ons. The EPA was petitioned for review of the 2012 NSPS for several issues, one of which was that pe titioners believed the EP A had underestimated the emissions from hydraulically fractured oil well comp letions 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 resp ect 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 natu ral 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 activitie s that involve re-drilling or re-f racturing an existing well. This chapter describes hydraulically fractured oil well co mpletions 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 co mpletions as were found to be appropriate for gas well completions. As such, a BS ER analysis was not necessary when considering control technology for applic ation to oil well completion emissi on. 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 c onvenience 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 form ations, but can vary between wells in the same formation. Over time, completion and recompletion ac tivities 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, perforat ing 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 prod uction to begin. 7



### Developmental wells are drille d within known boundaries of a pr oven oil or gas field, and are located near existing well sites where well parameters are alrea dy recorded and necessary surface equipment is in place. When drill ing occurs in areas of new or unknow n potential, well parameters such as gas composition, flow rate, and temperature from th e formation need to be ascertained before surface facilities required for production can be adequate ly 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 o il 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 re duced. Natural gas emissions are a resu lt of the backflow of the fracture fluids and reservoir gas at high pressure and veloc ity necessary to clean and lift excess proppant to the surface. Natural gas from the completion backflow es capes to the atmosphere during the reclamation of water, sand, and hydrocarbon liquids during the collec tion of the multi-phase mixture directed to a surface impoundment. As the fracture fluids are deplet ed, 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 back flow of the fracture fluids, comple tions involving hydr aulic fracturing have higher costs and vent substantially more na tural 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). Recomple tions are remedial operations required to maintain production or minimize the decline in production. Exam ples of the variety of recompletion activities include completion of a new producing zone, re-fract ure of a previously fractured zone, removal of paraffin buildup, replacing rod breaks or tubi ng tears in the wellbore, and addressing a malfunctioning downhole pump. During a recompletion, por table 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 speci al equipment, and are usually performed by well service contractors specia lizing 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 fract ure, except that surface gas collection equipment will already be present at the wellhead after the in itial 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 be ing produced by the well dur ing 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 fr ee 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, near ly all of the flowback emissions originate from the recompletion process but are vented as the flowb ack enters the impoundment or vessels. Minimal amounts of emissions are caused by the fluid (mostly water) held in the impound ment or vessels since very little gas is dissolved in the flui d when it enters the impoundment or vessels.



### 4.2 Emission Data a nd Emissions Factors
4.2.1 Summary of Major Studies and Emission Factors Together with the sources of information and data reviewed during th e development of the 2012 NSPS, the EPA reviewed recent data and information as was discussed in the wh ite paper titled “Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Asso ciated Gas during OngoingProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

15 

### 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 si gnificant emissions from oil well completions and recompletions. Table 4-1 presents a lis t of the studies or information s ources consulted for development of the NSPS development and the 2014 white paper. Th e 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 Documents a EPA 2013 Nationwide X

Inventory of GHG Emissions and Sinks: 1990-2012 b, c EPA 2014 Nationwide X

CH 4 Emissions from the U.S. Petroleum Industry (Draft) d Radian 1996 Nationwide X

CH 4 Emissions from the U.S. Petroleum Industry e ICF 1999 Nationwide X

Oil and Gas Emission Inventories for Western States f Western Regional Air Partnership 2005 Regional X X Recommendations for Improvements to the Central States Regional Air Partnership's Oil and Gas Emission Inventories g Central States Regional Air Partnership 2008 Regional X X

Oil and Gas Producing Industry in Your State h Independent Petroleum Association of America 2009 Nationwide

Emissions from Oil and Natural Gas Production Facilities i Texas Commission for Environmental Quality 2007 Regional X X

Petroleum and Natural Gas Statistical Data j 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 Operations k EPA 1999 X

Supplemental Generic Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program l 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

16 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 Standards m EPA 2012 Nationwide X X

Fort Berthold Federal Implementation Plan n EPA 2012 Regional X X ERG/EC/R Contractor Analysis of HPDI® Data o EPA 2012 Nationwide X X Environmental Defense Fund Analysis of HPDI Data p EDF 2014 Nationwide X X
Measurement of Methane Emissions at N atural Gas Production Sites in the United States q Allen et al. 2014 Nationwide X X

Methane Leaks from North American N atural Gas Systems r Brandt et al. 2014 Nationwide X X

a. U.S. EPA. GHG Emissions Reporting From the Petroleu m and Natural Gas Industry: Background TSD. Climate Change Division. Washington, DC. November 2010. 84-89 pp. b. U.S. EPA. Methodology for Estimating CH 4 and CO 2 Emissions from Petroleum Systems. GHG Inventory: Emission and Sinks 1990-2008. Washington, DC. 2010.

c. U.S. EPA. Methodology for Estimating CH 4 and CO 2 Emissions from Natural Gas Systems. GHG Inventory: Emission and Sinks 1990-2008. Washington, DC. 2010. d. Radian International LLC, Methane Emissi ons 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 Ga s Production Facilities. Prep ared for the Texas Commission on Environmental Quality. August 31, 2007. j. U.S. EIA. Annual U.S. Natural Gas Wellhead Price. EIA. Natural Gas Navi gator. 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/20140415 completions.pdf. p. Environmental Defense Fund (EDF). 2014. Co-Producing Wells as a Major Source of Methane Emissions: A ReviewProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

17 of Recent Analyses, March, 2014 . Available at http://blogs.edf.org/energyexchange/files/2014/03/EDF-Co-producingWells-Whitepaper.pdf. Supplemental materials availabl e 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/c ontent/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.nov im.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 th e case of oil wells, the proposed amendments to the NSPS) would be subject to emission control requirements. Likewise, wells drilled prior to the propo sal date of the NSPS (or the amended N SPS) would not be subject to emission control requirements unless they underwent a modificati on after the proposal date. Under section 111(a) of the CAA, the term “modification” means:
“any physical change in, or change in the met hod of operation of, a sta tionary source which increases the amount of any air pollutant emitted by su ch source or which results in the emission of any air pollutant not previously emitted.” The wellhead is defined as the piping, casing, t ubing, 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 existi ng 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. Additi onally, much of the emissions data on which this analysis is based demonstrates that hydraulic fracturing of any well results in an incr ease 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 performe d in order to recomplete the well, it was determined that a recompletion woul d 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 emi ssion source during completion and recompletion activities is the venting of natural gas to the atmo sphere during flowback. Flowback emissions are shortterm in nature and occur as a specific event duri ng 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 ven ting of emissions from the well during the initial phase of well preparation or during recompletion main tenance and/or re-fracturing of an existing well.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### This analysis assumes wells completed/recomple ted with hydraulic fracturing are found in tight sand, shale, or coal bed CH 4 

### formations. The basic approach for th is analysis was to use natural gas production data to approximate natural gas emissi ons from representative oil completions and recompletions and then estimate CH 4 

### and VOC emissions using a the representative gas composition values developed in the 2011 Gas Co mposition Memorandum for the 2012 NSPS. 9



### Based on comments received during the developmen t 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 gi ven the design and operating parameters of separation units operating in the fiel d. 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 ba se 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 gase s 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 GOR s less than 300 are at the lower end of this range, and will not likel y have enough gas associated that it can be separated. Therefore, for our analysis, we set a of GOR of less than 300 sc f/barrel as the threshold under which an oil well completion would not be reasonably capable of capt uring and controlling emissi ons. For our analysis, we
removed these oil wells from the evaluation to determ ine emissions from hydrauli cally fractured oil wells.
The following methodology was used to estimate the potential CH 4 

### and VOC from hydraulically fractured oil well completions.

1. The EPA obtained well production data from th e DrillingInfo database dated February, 2014. 12 

### The DrillingInfo database consists of oil and natural gas well info rmation maintained by a private organization that provides parameters desc ribing the location, opera tor, 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 comp iling primarily publically available oil and gas data, c onducting statistical analysis, and providing analysis platforms for customers. The DrillingInfo database is particularly focused on hist orical 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 o il production, well depth, and shut-i n 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 we lls 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/NES HAP DrillingInfo Processing Methodology " available in the docket for a detailed description of the process to identify hydraulically fractured oil wells fr om the total o il 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 complete d for the first time in 2012 or could have been re-completed (i.e., re-fractured in 2012). The EPA also removed a ll wells not characterized in the DrillingInfo database as defined as “oil,” “g as” or “oil and gas” from the dataset.
4. For the above identified hydraulically fractured oil well population, the EP A calculated the gas to oil ratio (GOR) by dividing the standard cubic feet (scf) of gas produced dur ing the first month of production by the barrels (bbl) of petroleum liqui d produced during the first month. The EPA then used the GOR to categorize the wells into oil a nd gas wells. Oil wells were defined to be those wells with a GOR of less than 100,00 0 scf/bbl. This threshold was c hosen because it is consistent
with the threshold used in the EPA National Em issions Inventory Oil and Gas Emission Estimation Tool and the threshold used in several states, including Texas 13 

### and New Mexico 14



### . 5. Based on the calculated GOR for th e wells identified above, we e liminated 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 da ily 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

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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 ye ar 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 pro duction during the first m onth was representative of the daily potential emissions during a hydraulica lly fractured oil well co mpletion. Therefore, the estimated gas production from a representative oil well completion was determined by taking the average of the average daily natural gas producti on 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 CH 4 

### and VOC emissions for a represen tative oil well completion or recompletion, we converted the av erage natural gas poten tial emissions per day to short tons of potential CH 4 

### and VOC emissions. The conversion factor s used are those developed for the NSPS
and outlined in the memorandum titled " Composition of Natural Gas fo r use in the Oil and Natural Gas Sector Rulemaking" , available in the docket. 15 

### Specifically, we assume natural gas is 46.71%
CH 4 

### by volume, the density of CH 4 

### is 0.0208 tons per Mcf, and that there is 0.8374 lbs of VOC per pound of CH 4



### . We then calculated the potential VOC and CH 4 

### emissions during a hydrau lically fractured oil well flowback by multiplying potential CH 4 

### and VOC emissions per day by the number of days in the average flowback event. The data sources referenced in the white papers not ed a range of flowback duration from 1-10 days. Some of th e values in the ranges were base d 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 anal ysis 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., un controlled) 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 potenti al emissions estimates (8 to around 200 tons CH 4 

### per completion or workover) for hydraulically fractured oil well completions. Some of the values were developed using data on gas producti on and assumptions about flowback; others used measurement data. The estimate presented in the table below was deve loped using a method relying on flowback and gas production data, which allowed the EPA to develop a fact or that reflects GOR thre sholds 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### that population of wells, in the absen ce of controls. To calculate emissi ons to the atmosphere using these values, additional information on gas th at is not emitted (e.g. through use of RECs or flaring) is needed to reduce the potential value.

Table 4-2. Uncontrolled Emissions Estimates fr om Representative Oil Well Completion or Recompletion
Average Daily Production Natural Gas (Mcf/event) Potential Emissions 

### CH 4 a (tons/event) Potential Emissions VOC b (tons/event) 3-Day Completion or Recompletion Event 999 9.72 8.14

a. It is assumed CH 4 comprises 46.732 percent by volume of natural gas. The factor used to convert CH 4 from volume to weight is 0.0208 tons CH 4 per thousand cubic feet (Mcf) of CH 4 . 16 b. Assumes 0.8374 lb. VOC/lb. CH 4 . 

### 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 na tionwide 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 recomple tions 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 emi ssions 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 calcula ting the number of hydraulically fractured oil well completions from the HPDI® database in 2012 identifie s 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 n ecessary to calculate a refracture frequency.
To more accurately estimate ba seline emissions for this analysis, and to ensure no emission
reduction benefits were calculated fo r sources already being controlled, it was necessary to evaluate the number of completions and recomp letions already subject to regula tion. The number of completions and recompletions already being controlled in the absen ce of federal regulation was estimated based on the existing State regulations that require control me asures for completions and recompletions. Although there may be regulations issued by other local ordi nances for cities and coun ties throughout the U.S., the

16 U.S EPA. Methodology for Estimating CH 4 and CO 2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 1990-2008. Washington, DC. 2010. Appendix B, Pgs. 87-89.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### number of wells impacted by local (as opposed to state le vel) regulations could not be determined because data for wells subject to co unty or local ordinance level regula tions are not available. Therefore, the calculated percentage of wells subject to state regulation based on the identified State regulations
should be considered a c onservative 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 exis ting controls. Colorado and Wyoming were the only States identified as requiring controls on completions prior to N SPS review. The State of Wyoming’s Air Quality Division (WAQD) requires operators to complete wells without flaring or ve nting where the following criteria are met: (1) the flowback ga s meets sales line specifications and (2) the pressure of the reservoir is high enough to enable REC. If th e above criteria are not met, then the produced gas is to be flared. 17 

### The WAQD requires that, “emission s of VOC and HAP associated with the flaring and venting of hydrocarbon fluids (liquids and gas) associated with well completi on and recompletion activities shall be eliminated to the extent practic able 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 cert ificate (REC) for both oil and natural gas wells. 18 

### It was assumed for this analysis that th e ratio of wells in Colorado and Wyoming to the total number of wells in the U.S. represents th e 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 reco mpletions as it was the only State id entified as having regulations directly regulated to reco mpletions. We used the referenced GOR of less than (<) 100,000 scf/bbl for oil wells to identify the oil we lls located in Wyoming and Colorado. From this review it was estimated that 7 percent of completions are controlled in absenc e of federal regulation. For the base year 2012 we estimated a total number of completions and recomp letions 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 explorator y 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 (8 05.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

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### (NEMS). NEMS is a model of the U.S. energy econom y 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 ava ilability 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 th eir 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 oi l 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 anal ysis detailed above.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### Table 4-3. Estimated Number of Hydraulically Fr actured 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 Recompletions a 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 fo r future dates. In orde r 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 Mode l. We calculated the com pound 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 completi ons 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 Recompletions a 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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, desc ribed above, nationwide emission estimates for oil well completions and recompletions in the base year 2012 and project ed 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 Wells a Baseline Nationwide Emissions (tpy) 

### CH 4 VOC 

### CH 4 b VOC b 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 CH 4 . 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 prove n 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 a nd completion combustion. As with natural gas wells, the use of a REC not only reduces em issions but delivers natural gas pro duct to the sales meter that would typically be vented. Completion co mbustion destroys the organic compounds. As both of these techniquesProposed 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 sale s line, and completion combustion was determined to
BSER when it is not feasible to dir ect the gas to a sales line), and base d on our research as published in the oil completions white paper, these technologies have been found to be technical ly feasible for oil well completions and recompletions, and are in use in th e industry to control emissions from oil wells. We identified no other potential control options for oi l 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 technologi es with respect to oil we ll 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 th e sales line. This process prevents some natural gas from venting and results in additional economic be nefit from the sale of captured gas and, if present, gas condensate. Additional equipment required to conduct a REC may include additional tankage, speci al 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 barri ers 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 an d production companies and/or pipeline companies constructing lines in explor atory fields. The State of Wyoming has set a precedent by stating proximity to gathering lines fo r wells is not a sufficient excuse to avoid RECs unless they are deemed explorator y, or the first well drilled in an area that has never had oil and gas well production prior to that dr illing instance (i.e., a wildcat well). 20 

### In instances where formations are stacked vertically and horizontal dr illing could take place, it may be possible that

19 U.S. EPA Fact Sheet No. 703: Green Completions. OAR: Na tural 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 sufficien t to overcome the sales line backpressure. This pressure is dependent on the specif ic 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 fl ow to the sales line. Another control option is compressor applications. One application is ga s lift which is accomplished by withdrawing gas from the sales line, boosting its pressure, and ro uting 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 th e concentration of inert ga s, such as nitrogen or CO 2 

### , in the flowback gas exceeds sales line c oncentration 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, sin ce 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 em issions described in Section 4.2. The emissions reductions vary according to reser voir characteristics and ot her parameters including length of completion, number of fractured zo nes, pressure, gas composition, and fracturing technology/technique. Based on information presented in the white papers, th is 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 Consulti ng. Percent of Emissions Recovered by Reduced Emission Completions. May 2011.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### 4.4.2.3 Cost Impacts All completions incur some costs to a compa ny. Performing a REC will add to these costs. Equipment costs associated with RECs vary from we ll 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 re sized rather than installi ng a portable dehydrator for temporary use during the completion. Some operators nor mally install equipment used in RECs, such as sand traps and three-phase separators, further re ducing incremental REC costs. The EPA received information and comment from multiple technical e xperts 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 TSD 22 

### , the annual cost of performing a REC was estimated to be $12,735 for a repres entative well completion lasting 3 days 23 

### . For our analysis, the cost is adjusted to 2012 dollars using the Gr oss Domestic Product: Implicit Price Deflator. 24 

### The resulting cost for performing a REC for a well completi on 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 capture d 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 fr acturing is approximately $3,597. When considering these savings from REC, for a completion or recomp letion with hydraulic fractur ing, 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. Th e 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.o rg/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

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### second method, the multi-pollutant method, allocates co sts among the pollutants that a given technology reduced (i.e., methane and VOC). This proration was based on estim ates 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 a llocated 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 at tributed to each polluta nt and the monetary gas savings is considered. Likewise, the cost is $564 pe r 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). Tabl e 4-6 provides a summary of REC cost per ton of
emission reduction.
In order to accomplish 95 percen t control, the combination of a combustion device and the REC
can be used. For the combined REC and combustion de vice 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 methan e 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 co st 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., NO x 

### , PM, etc.) would be generated, no wastes should be created, no wastewater ge nerated, and no electricity needed. Therefore, there are no secondary impacts expected due to REC.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 industria l settings, since the completion co mbustion device can normally handle
fluctuations in concentrati on, flow rate, heating value, and inert species content. 27 

### Completion combustion devices commonly found on drilling sites are rather crud e 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 mech anism 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 co mbustion devices do not employ an actual control device, and are not capable of being tested or monitored for efficienc y. They do provide a means of minimizing vented gas and is preferable to venting. For the purpose of th is 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 accura tely measure the destruction efficiency of a completion combustion device. The actual destruction e fficiency achieved in practice can be expected to vary with the amount of noncombusti ble gas and liquids in the gas flow. For the purposes of this analysis, a destruction efficiency of 95 percent, consistent with the e xpected destruction efficiency of a properly designed and operated flar e, 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. Ther efore, it is more reliable to install an igniter fueled by a consistent and continuo us ignition source. This scenario would be especially true for energized fractures where the initial flowback concen tration will be extremely high in inert gases. This analysis assumes the use of a continuous ignition s ource with an independent external fuel supply to achieve an average of 95 percent control over the entire flowback period. A dditionally, because of the nature of the flowback (i.e., with periods of wate r, condensate, and gas in slug flow), conveying the entire portion of this stream to a completion combustion device or ot her control device is not always feasible. Because of the exposed flame, open pit fl aring 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 F act Sheet: FLARES. Clean Air Technology Center.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

31 

### impacts in some situations (e.g., dry, windy conditions, pr oximity 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 re quirements of 40 CFR 60.18(b) do not apply to them. Concerns have been raised on appl icability of 40 CFR 60.18 w ithin the oil and gas in dustry including for the production segment. 28,29,30 

### The design and nature of completion combustion devices must handle multiphase flow and stream compos itions that vary during the flowback period. Thus, the applicability criterion that specifies conditions fo r flares used in highly industrial se ttings 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 estimat ed average completion combustion device cost of approximately $3,523 (2008 dollars). 31 

### For our analysis, this cost wa s adjusted to 201 2 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 comp letion 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 th at multiple completions and recompletions can be controlled with the same completion combustion de vice, not only for the lif etime of the combustion device but within the same yearly ti me period. However, to be conservative, costs were estimated as the total cost of the completion combus tion device itself, which corresponds to the assumption that only one device will control one completion per year. The cost per ton of emissions redu ced was then calculated in two ways. The first method allocated all of th e costs to each pollutant individually. The second method allocated costs among the pollutants that a given technology reduced (i.e., CH 4 

### 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 do llar years. For the combustion device the 2009 value equals the 2009 average value for the combustion device is $3,195.
32 See footnote 24.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 attrib uted 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 devi ce to reduce emissions from representative completions/recompletions are provided in Table 4-6.
Since this analysis assumed completion combus tion devices achieve 95 pe rcent efficiency over the duration of flowback, it is likely the secondary emission estimati ons 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 NO x 

### formulating is also likely. The degree of com bustion is variable and depends on th e rate and extent of fuel mixing with air and on the flame temper ature. Moreover, the actual NO x 

### (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 de vices discussed in Section 4.5 should be considered minimum estimates of secondary emissi ons from combustion devices.

4.4.3.4 Secondary Impacts Noise and heat are the two primary undesira ble outcomes of completion combustion device operation. In addition, combustion an d partial combustion of many pollu tants also create secondary pollutants including NO x 

### , CO, sulfur oxides (SO x 

### ), CO 2 

### , and smoke/particulates. The degree of combustion depends on the rate and extent of fuel mi xing 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 CH 4 

### content of the gas stream r outed to the completion combusti on device, it suggests that there should not be smoke except in specific circumstances (e.g., energized fracture s). 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 cu rrent 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 ope rations during natural gas well completions are limited. Guidelines published in AP-42 for flare opera tions are based on tests fr om a mixture containing

33 See footnote 25.
34 Ibid.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

33 

### 80 percent propylene and 20 percent propane. 35 

### These emissions factors, howe ver, are the best indication for secondary pollutants from flare operations current ly available. These sec ondary emission factors are provided are provided in Ta ble 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 OOOOaBackground Technical Support Document34Table 4-6. Reduced Emission Completion and Combustion Emission Reductions and Cost Impacts SummaryControl TechnologyEmissionsReduced PerCompletiona(short tons)Volume of WholeGas Captured(Mcf/completion)Value ofWhole GasCaptured($/completion)AnnualCost($)Cost of Control PerCompletion(excluding gas savings)($/short ton)Cost of Control PerCompletion(including gas savings)($/short ton)CH4VOCCH4VOCCH4VOCREC (100)b8.75 7.33 899 $3,597 $13,459 $1,539 $1,837 $1,127 $1,346REC (50/50)c8.75 7.33 899 $3,597 $13,459 $769 $919 $564 $673REC and Combustiondevice (100)b,d9.23 7.73 899 $3,597 $17,183 $1,861 $2,222 $1,471 $1,757REC and Combustiondevice (50/50)c,d9.23 7.73 899 $3,597 $17,183 $930 $1,111 $736 $879CompletionCombustion (100)b9.23 7.73 0 $0 $3,723 $403 $481 $403 $481CompletionCombustion (50/50)c9.23 7.73 0 $0 $3,723 $202 $241 $202 $241a. Assumes 95% control.b. Scenario where 100 percent of the cost ofcontrol 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### Table 4-7. Emission Factors from Flare Oper ations from AP-42 Guidelines Table 13.4-1 a

Pollutant Emission Factor (lb/10 6 Btu) 

### THC b 

### 0.14

CO 0.37 NO x 

### 0.068 PM c 

### 2.56e-3 CO 2 d 

### 60 a. Based on combustion effi ciency of 98 percent. b. Measured as CH 4 equivalent. c. Soot in concentration values: nonsmoking flares, 0 micrograms per liter (μg/L); lightly smoking flares, 40 μg/L; average smoking fl ares, 177 μg/L; and heavily smoking flares, 274 μg/L. d. Carbon dioxide is measured in kg CO 2 /MMBtu and is derived from the CO 2 emission factor obtained from 40 CFR Part 98, subpart Y, Equation Y-2. 

### 4.5 Regulatory Options
The REC pollution prevention approach w ould not result in emissions of CO, NO x 

### , and particulate matter (PM) from th e combustion of the completion gases in the completion combustion device, and would therefore be the preferred opti on. As discussed above, REC is only an option for reducing emissions from gas well completions/workovers with hydrauli c fracturing. Taking this into consideration, the following regulatory alternatives were evaluated:

 Regulatory Option 1. Require completion co mbustion devices for all hydraulically fractured oil well completions and recompletions;

 Regulatory Option 2. Require REC for all hydraulic ally fractured oil well completions and recompletions;

 Regulatory Option 3. Require REC and combus tion operational standa rds for hydraulically fractured oil well completions and recompleti ons, with the exception of exploratory, and delineation wells; and

 Regulatory Option 4. Require comb ustion operational standards for completions of exploratory
and delineation wells. The following sections discu ss these regulatory options.
4.5.1 Evaluation of Re gulatory Options
Under Regulatory Option 1, nearly all of the na tural gas emitted from the well during flowback would be destroyed by sending flowback gas through a combustion unit. Not only would this regulatoryProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

36 

### option result in the destruction of a natural resource w ith no recovery of salable gas, it also would result in an increase in emissions of secondary pollutants (e.g., NO x 

### , CO, etc.). Therefore, Regulatory Option 1 was rejected.
The second regulatory option woul d require RECs for all completions and recompletions of hydraulically fractured oil wells. As stated previous ly, 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 duri ng completion and recompletion activities due to the variability of the pressure of produced gas and/or inert gas concentrations. Th erefore, Regulatory Option 2 was rejected.
The third regulatory option was to require an operational standa rd consisting of a combination of REC and combustion for hydraulically fractured o il well completions. As discussed for Regulatory Option 2, RECs are not feasible for every well at all times during comp letion 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 co ntinue to reduce emissions when RE Cs are not feasible due to well characteristics (e.g., wellhead pressure or inert gas c oncentrations), Regulatory Option 3 also allows for the use of a completion combustion device in combin ation with RECs. Under section 111(h)(2) of the CAA, the EPA can set an operational standard which represents the best syst em of continuous emission reduction, provided the following criteria are met:
“(A) a pollutant or pollutants cannot be emitte d through a conveyance designed and constructed to emit or capture such pollutant, or that any re quirement for, or use of, such a conveyance would be inconsistent with any Federa l, State, or local law, or (B) the application of measurement methodology to a particular class of sources is not practicable due to technologi cal 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 maki ng an operational standard appropriate. Therefore, an operational standard under this regulatory option consists of a co mbination of REC and a completion combustion device to minimize the venting of natura l 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 th is regulatory option, to maintain documentation ofProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

37 

### the overall duration of the completion event, durati on of recovery using REC, duration of combustion, duration of venting, and specific reasons for venting in lieu of combustion. It wa s also evaluated whether Regulatory Option 3 should apply to all well completions, incl uding exploratory and delineation wells.
As discussed previously, one of th e technical limitations of RECs is that they are not feasible
for use at some wells due to thei r proximity to gas pipelines. Secti on 111(b)(2) of the CAA allows EPA to “...distinguish among classes, types, and sizes w ithin categories of new sources for the purpose of establishing....” performance standa rds. Due to their distance from sales lines, and the relatively unknown characteristics of the formation, completion ac tivities occurring at expl oratory 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 hydr aulic fracturing that do not fit the definition of exploratory or delineat ion wells. Subcategory 2 wells that meet the following definitions of exploratory
or delineation wells:

 Exploratory wells are wells outsi de 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 dr illed in order to determin e the boundary of a field or producing reservoir.
Based on this subcategorization, Regulatory Op tion 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 co mbustion for the Subcategory 2 wells. As discussed above, a REC is not an option for exploratory and delinea tion wells based on their distance from sales lines. As with the Regulator y Option 3, a numerical lim itation is not feasible. Therefore, this regulatory option requires an oper ational standard where emissions are minimized using a completion combustion device during completion activit ies at Subcategory 2 we lls, with an allowance for venting in situations where combustion presents sa fety hazards or other conc erns or for periods when the flowback gas is noncombustible due to high c oncentrations of inert ga ses. Consistent with Regulatory Option 3, records would be required to document the ove rall duration of the completion event, the duration of combustion, th e 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 toProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

38 

### undesirable loss of natural gas or te chnical 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 sec ondary environmental impacts relate d to Regulatory Options 3 and 4 which were selected as viable options for sett ing standards for completions and recompletions.
4.5.2.1 Primary Environmental Impact s of Regulatory Options Regulatory Options 3 and 4 were selected as opt ions for setting standards for completions and regulatory options as follows:

 Regulatory Option 3. Operational standard for completions and recomp letions with hydraulic fracturing for Subcategory 1 wells (i.e., wells wh ich do not meet the definition of exploratory or delineation wells), which re quires a combination of REC w ith combustion, but allows for venting during specified situations.

 Regulatory Option 4. An operational standard fo r completions with hydraulic fracturing for exploratory and delineation we lls (i.e., Subcategory 2 wells ) which requires completion
combustion devices with an allowance fo r venting during specified situations.
The number of completions and r ecompletions that would be subj ect to the regulatory options listed above was presented in Tabl e 4-3. From Table 4-4, it was estim ated that there would be an estimated 13,806 hydraulically fractured developmenta l 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 uncont rolled exploratory oil well completions and recompletions with hydraulic fracturing in 2020 a nd 1,100 oil well completions and recompletions in
2025. Because not all wells will have available infr astructure or will not ot herwise be technically eligible to conduct RECs, we estimate that 50 percen t of the uncontrolled subcategory 1 oil wells will be affected by the REC requirement and the other 50 percent will control em issions by combustion.

Table 4-8 summarizes the nationwide emission reduction estimates for each regulatory option for the projected years 2020 and 2025. It was estimate d that RECs in combination with the combustion of gas unsuitable for entering the gathering line, can achieve an ove rall 95 percent VOC reduction over the duration of the completion or recompletion operation. The 95 percen t recovery was estimated basedProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

39 

### on 90 percent of flowback being cap tured to the sales line and assumi ng an additional 5 percent of the remaining flowback would be sent to the combus tion device. Nationwide em ission reductions were estimated by applying this 95 per cent VOC reduction to th e uncontrolled baseline emissions presented
in Table 4-4.

4.5.2.2 Cost Impacts The operational standards for Regulatory Opti ons 3 and 4 include both REC and a completion combustion device, therefore the total incremental co st of the operational sta ndard 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 comp letion combustion device. Applying the cost for the combined REC with comp letion combustion device to the estimated 6,903 and combustion device only to the estimated 6,903 Sub category 1 completions and recompletions in projected year 2020, the total nationwide cost wa s estimated to be approximately $119 million, which includes an estimated annual savings of approxi mately $25 million when natural gas savings are considered. Likewise, for projected year 2025, the co st for RECs with com bustion device applied to 6,902 Subcategory 1 completions and recompletions a nd the cost for combusti on only applied to 6,902 Subcategory 1 completions and recompletions, th e 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 Regulat ory Option 4, the costs for completion combustion devices presented in Table 4-6 would apply to Subcategory 2 completi ons. The cost per completion event was estimated to be $3,723. Applied to the 870 estimated Subcategory 2 co mpletions and recompletions in projected year 2020, the nationwide costs were estimated to be $3.2 million.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document40Table 4-8. Nationwide Emission and Cost Analysis of Regulatory OptionWell Completion CategoryNumber ofSourcesSubject toNSPSaAnnual CostPerCompletionEventb($)Nationwide EmissionReductionsc(tpy)Total Nationwide Costs($/year)MethaneVOCwithout savingswith savingsdBase Year 2012Regulatory Option 31. Development Oil Wellse6,906 $17,183 63,766 53,398 $118,664,480 $93,822,9391. Development Oil Wellsf6,906 $3,72363,766 53,398 $25,714,478 $25,714,478Regulatory Option 42. Exploratory/Delineation Oil Wells 545 $3,723 5,032 4,214 $2,029,306 $2,029,306Combined Option 3 and 414,357 NA 132,565 111,010 146,408,265 121,566,723Projected Year 2020Regulatory Option 31. Development Oil Wellse6,903 $17,183 63,739 53,375 $118,614,014 $93,783,0371. Development Oil Wellsf6,903 $3,72363,73953,375$25,703,542 $25,703,542Regulatory Option 42. Exploratory/Delineation Oil Wells 870 $3,723 8,037 6,730 $3,241,154 $3,241,154Combined Option 3 and 414,677 NA 135,516 113,481 147,558,710 122,727,733Projected Year 2025Regulatory Option 31. Development Oil Wellse6,902 $17,183 63,726 53,364 $118,588,789 $93,763,0931. Development Oil Wellsf6,902 $3,72363,726 53,364 $25,698,076 $25,698,076Regulatory Option 42. Exploratory/Delineation Oil Wells 1,166 $3,723 10,770 9,019 $4,343,048 $4,343,048Combined Option 3 and 414,970 N/A 138,221 115,747 148,629,913 123,804,217a. Number of sources in each well completion category that are uncontrolled atbaseline 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 Option 4 is a completioncombustion device only.c. Nationwide emission reductions calculated by applying the 95 percent emission reduction efficiency to the uncontrolled nationwide baseline emissionsin 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 a total savings of$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 support a REC).f. These well completions are estimated to not be eligible to conduct a REC and must combust emissions.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

41 

### 4.5.2.3 Secondary Impacts Regulatory Options 3 and 4 requi re 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 th e volume of gas captured, combusted and vented may vary significantly depending on well charact eristics and flowback compositi on, for the purpose of estimating secondary impacts for Regulatory Op tions 3 and 4, it was assumed that 90 percent of flowback is captured and an additional 5 percent of the rema ining gas is combusted. For Subcategory 1 oil well completions and recompletions with hydraulic fractur ing, it is assumed around 50 Mcf (5 percent of 999 Mcf) of natural gas is combusted on a per well ba sis when a REC is perfor med. 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 flowb ack emissions are combusted by th e combustion device. The ns of pollutant emissions per completion event was es timated 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 we ll completions and recompletions controlled by
a REC combined with a combustion devi ce, it is estimated 0.002 tons of NO x 

### 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 NO x 

### are produced in secondary emission s per event. This is based on the assumption 95 percent of flowback gas is combuste d by the combustion device. Based on the estimated number of completions and recomp letions for projected year 2020, the proposed regulatory options are estimated to produce around 300 tons of NO x 

### in secondary emissions nationw ide from controlling all or partial flowback by combustion. Table 4-9 summarizes th e estimated secondary emi ssions of the selected regulatory options for projected y ear 2020 and Table 4-10 summarizes th e estimated secondary emissions of the selected regulatory op tions for projected year 2025.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document42Table 4-9. Nationwide Secondary Impacts of Selected Regulatory Options for Projected Year 2020aPollutantRegulatory Option 3b,cRegulatory Option 4dCombinedOptions1. Developmental Oil Well - REC1. Developmental Oil Well - Combustion2. Exploratory/Delineation OilWellEmissions perCompletionEvent(tons)NationwideSecondaryEmissions(tpy)Emissions perCompletion Event(tons)NationwideSecondaryEmissions(tpy)Emissions perCompletionEvent(tons)NationwideSecondaryEmissions(tpy)NationwideSecondaryEmissions(tpy)THC0.004 26 0.076 526 0.076 66 619CO0.010 69 0.201 1,390 0.201 175 1,635NOx0.002 13 0.037 255 0.037 32 300PM0.000 0 0.001 9 0.001 1 10CO23.599 24,846 71.987 496,924 71.987 62,628 584,399a. Nationwide impacts are based on AP-42 Emission Guidelines for Industrial Flares as outlined in Table 4-7. As such, these emissions should be considered theminimum 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 flowback gas. 95 percent of theremaining flowback is assumed to be combusted by the combustion device. Therefore, it is estimated 50 Mcf is combusted per completion event. This analysisassumes 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 unitand 902 Mcf is combusted per completion. This analysis assumes6,903 development oil wellcompletions 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 assumes870 exploratory wells fall into thiscategory.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document43Table 4-10. Nationwide Secondary Impacts of Selected Regulatory Options for Projected Year 2025aPollutantRegulatory Option 3b,cRegulatory Option 4dCombinedOptions1. Developmental Oil Well - REC1. Developmental Oil Well - Combustion2. Exploratory/Delineation OilWellEmissions perCompletionEvent(tons)NationwideSecondaryEmissions(tpy)Emissions perCompletion Event(tons)NationwideSecondaryEmissions(tpy)Emissions perCompletionEvent(tons)NationwideSecondaryEmissions(tpy)NationwideSecondaryEmissions(tpy)THC0.004 26 0.076 526 0.076 84 636CO0.010 69 0.201 1,390 0.201 221 1,681NOx0.002 13 0.037 255 0.037 41 309PM0.000 0 0.001 9 0.001 1 10CO23.599 24,843 71.987 496,852 71.987 79,185 600,880a. Nationwide impacts are based on AP-42 Emission Guidelines for Industrial Flares as outlined in Table 4-7. As such, these emissions should be considered theminimum 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 flowback gas. 95 percent of theremaining flowback is assumed to be combusted by the combustion device. Therefore, it is estimated 50 Mcf is combusted per completion event. This analysisassumes 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 unitand 902 Mcf is combusted per completion. This analysis assumes6,902 development oil wellcompletions 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 assumes1,100 exploratory wells fall intothis category.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### 4.6 Comparison of Flowback Emissions Es timate Methodology to Measured Emissions from UT-Austin – Allen et al. Study 36



### 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. Howe ver, data from Allen et al can be used to assess the emissions estimation methodology de scribed 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 Alle n et al. to an estimate of potential well completion emissions calculated using data fr om the first month of gas producti on for those wells. For three of the four wells included in his assessment, the measured pot ential 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 ga s 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 co mpletions 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 we ll 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 comple tions 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.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document45Table 4-11. Comparison of FlowbackEmissions Estimate Methodology toMeasured Emissions from theUT Austin - Allen et al. StudyWell IDGOR(scf/bbl)First MonthGas ProductionRate(Mcf/day)aDuration ofFlowback(days)Gas ProductionRate x Durationof Flowback(Mcf)Estimated PotentialCH4Emissionsb(Mcf/completion)MeasuredPotential CH4Emissionsa(Mcf)Ratio of MeasuredPotential Emissionsto EstimatedEmissionsGC-1 4,046 3,000 3.13 9,375 4,381 5,000 1.14GC-2 4,267 2,700 3.17 8,550 3,995 4,250 1.06GC-6 30,703 6,100 6.83 41,683 19,479 12,200 0.63GC-7 3,508 1,500 4.50 6,750 3,154 4,320 1.37a. 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 aninitial flowback to an open top tank that lastedfor 28 hours. After 28 hours, the flow was directed to a separator and the gas from the separator was then sent to sales and aflare. In this case 28 hours was defined as theduration of the flowback, as reported by the company, since gas had begun to go to sales. The study team reported emissions from this flowback that included emissionsfrom the flare, which occurred after the initial 28 hours of flowback.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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
CH 4 

### and VOC emissions. This chapter explains the causes for these fugitive emissions, and provides
CH 4 

### and VOC emission estimates for “model” facilities in the production and transmission and storage segments. In addition, nationwide equipment fug itive emission estimates from new sources are estimated. Programs that are designed to reduce fugitive emissions are explained, along with costs, emission reductions, and secondary imp acts. Finally, this chapter discus ses considerations in developing regulatory alternatives for fugitive emissions from equipment.


### 5.1 Fugitive Emissions Description
There are several potential sources of fugitiv e emissions throughout the oil and natural gas source category. Fugitive emissions occur when conn ection points are not fitted properly or when seals and gaskets start to deteriorate. Ch anges 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, flange s, instruments, meters, open-ended lines (OELs), pressure relief devices, pump seals, valves or impr operly 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 rule 37 

### and the intended definition for the pur poses of addressing fugitive emissions. Therefore, we have defined a new term, "fugitive em issions 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, cr ankcase vents, blowdown vents, pump seals or diaphragms, compressors, separators, pressu re vessels, dehydrators, h eaters, instruments, and meters. Devices that vent as part of normal operati ons, such as a gas-driven pneumatic controller or a

37 The Oil and Natural Gas Sector NSPS (40 CFR 60, subpart OO OO) 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 th e manner in which the term is currently used in subpart OOOO.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

47 

### 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 or iginating from sites other than the vent, such as the seals around the bellows of a diaphragm pu mp, would be considered fugitive emissions.
In April of 2014, the EPA published a white paper 38 

### which summarized the EPA’s current understanding of CH 4 

### 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 po tential 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 industr y. Many of the fugitive emission measurements were conducted with EPA Method 21 instruments (e.g., or ganic vapor analyzer (OVA), flame ionization detector, flow measurement devi ces). 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 facili ty. Fugitive emission estimates for CH 4 

### and VOC ranged from 1.4 to 32 tons per year (tpy) and 0.4 to 10 tpy, respec tively for oil and natural gas production sites. Even though there is a wide vari ation in the potential CH 4 

### 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 natura l 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 categor y can consist of a variety of combinations of process equipment and other components. This is pa rticularly 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/oilandga s/2014papers/2 0140415leaks.pdf.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

48 

### industry, where “surface sites” can vary from site s where only a wellhead a nd associated piping is
located to sites where a substantia l 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 us ed. 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 study 39 

### and other sources. The GRI/EPA document provided average fugitive emissions component counts for natural gas producti on, natural gas processing, natural gas transmission and natural gas storage including; valves, connector s, OELs, and pressure relief valves (PRVs). Although these counts do not include all potential f ugitive 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, transmissi on stations, and storage f acilities). These fugitive emissions component counts are cons istent with those contained in the EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks, and in the EPA’s analysis to estimate CH 4 

### 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 fo r 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 Estimates a EPA 1995 None X X

CH 4 Emissions from the Natural Gas Industry: Equipment Leaks b GRI/EPA 1996 Nationwide X X

GHG Reporting Program c EPA 2013 Facility X Inventory of GHG Emissions and Sinks: 1990-2013 d 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).Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

49 Report Name Affiliation Year of Report Activity Factor(s) Emissions Data Control Options Measurements of CH 4 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 Report f City of Fort Worth 2011 Fort Worth, TX X X

Measurements of Well Pad Emissions in Greeley, Colorado g ARCADIS/Sage Environmental Consulting/EPA 2012 Colorado X X

Quantifying Cost-Effectiveness of Systematic Leak Detection and Repair (LDAR) Programs Using Infrared (IR) Cameras h Carbon Limits 2013 Canada and the U.S. X X

Mobile Measurement Studies in Colorado, Texas, and Wyoming i EPA 2012 and 2014 Colorado, Texas, and Wyoming X X

Economic Analysis of CH 4 Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries j ICF International 2014 Nationwide X X

Identification and Evaluation of Opportunities to Reduce CH 4 Losses at Four Gas Processing Plants k 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 Sites l 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 Stre et, NW NAS 340 Washington, DC 20001 USA. October 29, 2013. 6 pgs. Available at http://www.pnas.org/cont ent/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/gas wells/default.aspx?id=87074.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

50 g. Modrak, Mark T., et al. Understanding Direct Emissions Measurement Approaches for Upstream Oil and Gas Production Operations. Air and Waste Management Association 105 th 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 Measur ements, Interim Report on Recent Studies. Proceedings of the 105 th 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 Reduc tion 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 equi pment vary from site-to-site. Some production sites may include only a single wellhead that is extr acting oil or natural gas from the ground, while other sites may include multiple wellheads attached to a we ll pad. A well site is a site where the production, extraction, recovery, lifting, stabiliz ation, 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 (includi ng 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 eq uipment 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 f ugitive emissions components located at a natural gas well site. The types of production equipment lo cated 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, O ELs, and PRVs. Component counts for each of the production equipment items were cal culated using the average compone nt counts for onshore production equipment in the Eastern U.S and the We stern U.S. from the EPA/GRI report.
For oil wells, component counts were obtained from an American Petroleum Institute (API)
workbook 40 

### . The types of oil well production equipment incl ude: oil well heads, separators, headers and heater/treaters. Fugitive emi ssions components counts for these production equipment types were

40 API Workbook 4638, 1996.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

51 

### estimated using the average com ponent counts for onshore production eq uipment 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® database 41 

### . EPA estimated the number of wells on a typical well site using a spatial analysis of producing crude oil an d natural gas wells from the DrillingInfo HPDI
database 42 

### . Baseline fugitive emissions from well site s depend upon the quantity of equipment and components, which in turn is based on this estim ate 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 th at identified new and existing wells within a given distance of a new well completion or recompletion. This distance was assu med to represent the distance that, if other wells were within the distance, the well s 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 esti mate the average number of well co-located on a well site drew upon the latitude and longitude of new well completions a nd recompletions as well as the coordinates of all wells producing oi l or natural gas in 2012. The first algorithm estimated the distances between each new completion and recompletion and a ll producing wells, whic h also includes wells newly completed and producing in 2012, within the sa me 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 iden tify all co-located wells in the U.S. The number of new well completions and recompletio ns 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 visu al 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 th is 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

52 

### We estimated the number of wells per site assu ming 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 analys is 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 site s include about 8,500 existi ng 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 p er 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 Wel l 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 2.33Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

53 HPDI Basin No. Of Sites Oil Well Completions Natural Gas Wel l 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 1.10Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

54 HPDI Basin No. Of Sites Oil Well Completions Natural Gas Wel l 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 concentr ation of wells at productio n sites varies greatly by basin. However, the analysis indi cates 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-le vel, 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 site s averaged 1.79 wells per site while natural gas wells averaged 1.86. As a result of this analysis, based upon professi onal 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 recomple tions. Also, to simplify analysis of co sts and emissions at well sites, we rounded the 1.81 national averag e 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. Firs t, industry and state regulatory
trends indicate that we ll drilling will likely become increasingl y concentrated on sites, potentially leading to an increase in the aver age number of wells per well site. Ho wever, it is not possible at this point to forecast this increasing co ncentration, especially with the va riations by fields described above. Also, it is possible that two acres is too small to accu rately 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

55 

### Alternatively, the assumed two acre mi ght 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 like ly incorrect or exact duplicates of other wells. Despite these caveats, we believe that the well site analysis desc ribed here produces a reas onable 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 th e 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 nu mber 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 pr oduction 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 su mmary of the fugitive emissions component counts for natural gas production well site s 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 averag e component count for an oil well were determined to be 0.7 separators, 0.7 headers, and 0.03 heater/tr eaters per well. The total oil production well site component counts were cal culated by multiplying the average well production equipment values by the average numb er of oil wells per oil well site (2), and rounding the product to the nearest integer. Average component counts obtain ed from the API workbook were used to calculate the total number of components by multiplying th e rounded component counts by the component count per production equipment and rounding up to the neares t 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-42 44 

### . Annual emissions were calcula ted 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)Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

56 

### each year. The emissions factors are provided fo r total organic compounds (TOC) and include nonVOCs such as CH 4 

### and ethane. The emission factors used to estimate the new source emissions from the production segment (e.g., oil production well sites, na tural 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 NSPS 45 

### . A summary of the fugitive emissions component counts, average CH 4 

### emissions factors, CH 4 

### 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 CH 4 

### 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 CH 4 

### and 0.30 tpy of VOC. These emissions were used to estim ate the potential emission reductions and cost of control of a fugitive emissions reduction program.
The estimates presented here were develope d 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 distri bution for emissions rela ted to leaks, where a majority of emissions come from a minority of sour ces. 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, a nd 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 th e surveyed well sites accounted for 80% of total emissions. Both studies by Clearstone Engineering, Lt d. showed skewed distributions of leak emissions at processing plants, and the two mobile measurem ent studies observed skewed distributions at well sites. Since publication of the white paper, additiona l data have become available on fugitive emissions at well sites, including repor ting year 2013 data from GHGRP, which included onshore production fugitive emissions of 8,719,385 tons CO 2 

### e 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

57 

### 5.2.2.2 Gathering and Boosting Station Gathering and boosting stations are sites that collect oil and natura l gas from well sites and direct them to the natural gas processing plants. These st ations have similar pro duction equipment (including separators, meters, piping, compressor s, in-line heaters, de hydrators and other production equipment) to well sites; however they are not di rectly connected to th e wellheads. The gather ing and boosting station model plant was developed using the average fugitive emissions component counts for onshore production from the GRI/EPA study. The average com ponent 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 we ighted averages of the data se ts were determined to be 11 separators, 7 meters/piping, 5 gath ering compressors, 7 in-line heater s, and 5 dehydrators. Fugitive emissions component counts for each of the pro duction equipment items were calculated using the average component counts for onshor e production equipment in the Eastern U.S and the Western U.S. from the EPA/GRI study. The components for gatheri ng compressors were included in the model plant total counts, but the compressor seal s were excluded. Compressors seals are addressed in a Chapter 8 of this document. A summary of the fugitive emissions component counts for o il and gas gathering and boosting stations are presented in Table 5-9.

Baseline emissions were calculated us ing the component counts and the CH 4 

### emission factors for oil and natural gas production (See Table A-3). Th e baseline emissions fo r gathering and boosting stations are summarized in Table 5-10. The averag e fugitive emissions from a gathering and boosting station were determined to be 35.1 tpy of CH 4 

### 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, additi onal 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: Measurem ent Results study published in 2015. 46 

### This study measured facility-level emissions, including fugitive emissi ons, at gathering and processing
facilities. Data sets for both faci lity 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 fa ctors used in this analysis.

46 Mitchell, Austin L. et al. Measurements of Methane Emissions from Na tural Gas Gathering Facilities and Processing Plants: Measurement Results. Environ. Sci.Technol. 2015, 2119-3227.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document58Table 5-4.Average Fugitive Emissions Component Countfor Gas Production Well Site Model PlantProductionEquipmentModel PlantProductionEquipmentCountsAverage Component Count Per Unit ofProduction EquipmentaAverage Component Count Per Model PlantValvesConnectorsOELsPRVsValvesConnectorsOELsPRVsGas Wellheads 2 9 37 1 0 19 74 1 0Separators 2 22 68 4 1 43 137 7 2Meters/Piping 1 13 48 0 0 13 48 0 0In-Line Heaters 1 14 65 2 1 14 65 2 1Dehydrators 1 24 90 2 2 24 90 2 2Total 113 414 12 5Rounded up Total 114 414 14 6a. Data Source: EPA/GRI, CH4Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-080h)Table 5-5.Average Fugitive Emissions Component Countfor Oil Production Well Site Model PlantProductionEquipmentModel PlantProductionEquipmentCountsAverage Component Count Per Unit ofProduction EquipmentaAverage Component Count Per Model PlantValvesConnectorsOELsPRVsValvesConnectorsOELsPRVsOil Wellheads 2 5 18 0 0 10 36 0 0Separators 1 6 22 0 0 6 22 0 0Headers 1 5 14 0 0 5 14 0 0Heater/treaters 1 8 32 0 0 8 32 0 0Total 29 104 0 0Rounded up Total 29 104 1 1a. Data Source: EPA/GRI, CH4Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-080h)Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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

Component Type Component Service Emission Factor a (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 Na tural Gas Production Well Site Model Plant

Natural Gas Well Site Model Plant Component Model Plant Component Count a Uncontrolled Emission Factor b

(kg/hr/comp) Uncontrolled Emissions (tpy) CH 4 c VOC d
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. CH 4 emissions calculated using 0.695 weight ratio for CH 4 /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 fo r Oil Production Well Site Model Plant

Natural Gas Well Site Model Plant Component Model Plant Component Count a Uncontrolled Emission Factor b

(kg/hr/comp) Uncontrolled Emissions (tpy) CH 4 c VOC d 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 pl ant 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. CH 4 emissions calculated using 0.695 weight ratio for CH 4 /TOC obtained from gas composition memorandum. d. VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from gas composition memorandum.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document60Table 5-9.Average Fugitive Emissions Component Count for Gathering and Boosting Station Model PlantProductionEquipmentModel PlantProductionEquipmentCountsAverage Component Count Per Unit ofProduction EquipmentaAverage Component Count Per Model PlantValvesConnectorsOELsPRVsValvesConnectorsOELsPRVsSeparators 11 22 68 4 1 242 748 44 11Meters/Piping 7 13 48 0 0 91 336 0 0GatheringCompressors5 71 175 3 4 355 875 15 20In-Line Heaters 7 14 65 2 1 98 455 14 7Dehydrators 5 24 90 2 2 120 450 10 10Total 906 2,864 83 48Rounded up Total 906 2,864 83 48a. Data Source: EPA/GRI, Methane Emissions from the Natural GasIndustry, Volume 8: Equipment Leaks, Table 4-4 and 4-7, June 1996. (EPA-600/R-96-080h)Table 5-10.Estimated Fugitive Emission Estimate Gathering and Boosting Station Model PlantGathering andBoosting StationModel PlantComponentModel PlantComponent CountUncontrolledEmission Factora(kg/hr/comp)Uncontrolled Emissions(tpy)CH4bVOCcValves 906 0.0045 27.35 7.603Connectors 2,864 0.0002 3.84 1.068OELs 83 0.002 1.11 0.310PRVs 48 0.0088 2.83 0.788Total 35.1 9.77a. TOC emission factors obtained from Table 2-4 for the EPA Equipment Leaks Protocol for components in gas service.b. Methane emissions calculated using 0.695 weight ratio for CH4/TOC obtained from gas composition memorandum.c. VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from gas composition memorandum.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 pr oduction fields or natural gas pro cessing facilities, in transmission pipelines, to natural gas distributi on pipelines, or into storage. In addition, transmission stations may include production equipment for liquids separation, na tural gas dehydration, and tanks for the storage of water and hydrocarbon liquids. Resi due (sales) gas compression operated by natural gas processing facilities are included in the onshore natural gas pro cessing segment and are excluded from this segment. The segments include fugitive emissions from component s related to inlet and outlet pipelines, meter runs, dehydrators, and other piping located at the compressor buildi ng for transmission and storage stations, and injection/withdrawal compone nts associated with the injection/withdr awal 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 boosti ng stations. Fugitive emissions component counts and
CH 4 

### emission factors were obtained from the EPA/ GRI study. A summary of the fugitive emissions component counts, component em ission factors and baseline CH 4 

### and VOC emissions for transmission and storage model plants are pres ented in Table 5-11. The average f ugitive emissions for transmission stations were determined to be 62.4 tpy of CH 4 

### and 1.73 tpy of VOC and 164.4 tpy of CH 4 

### and 4.55 tpy of VOC for storage facilities. These emissions were used to estima te the potential emission reductions and cost of control of a fugitive emissions reduction program.

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

Component Model Plant Component Count a Component CH 4 Emission Factor a (Mscf/year/component) CH 4 Emissions b (tpy) VOC Emissions c (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 0.006Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

62 Component Model Plant Component Count a Component CH 4 Emission Factor a (Mscf/year/component) CH 4 Emissions b (tpy) VOC Emissions c (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 CH 4 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 co unt by the component CH 4 emission factor and converting to tons using the conversion factor 0.02082 tons CH 4 /Mscf CH 4 . c. VOC emissions calculated using 0.0277 weight ratio for VOC/CH 4 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 emi ssions 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 na tural gas production and transmission and storage segments were calculated using the equipment and fugitive emissions component counts and the representative gas service emissi on factors. Emissions were estimat ed using the EPA Protocol for Equipment Leak Emission Estimates which provided TOC emission factors for production sources (well sites, gathering and boosting) a nd the GRI/EPA study which provided CH 4 

### emission factors for transmission and storage facilities. The VOC emissions were calculated us ing weight fractions provided in the gas composition memorandum.

5.3.2 Activity Data Data from oil and natural gas technical documen ts and inventories were used to estimate the
number of new sources for each of the oil and natu ral gas segments. Information from the Drillinginfo HPDI® database, GHG Inventory were used to estimat e the number of new well sites, gathering and boosting stations, and transmission and storage facilities. A summary of th e steps used to estimate the new sources for each of the oil and gas segmen ts is presented in the following sections.

5.3.2.1 Well Sites The Drillinginfo database provided the informati on 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 eff ective date of the revised NSPS. Based on our research, four states have recen tly enacted State leak re gulations. Colorado, Ohio, Wyoming and Utah. Below is a brief di scussion of these state regulations:Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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###  Colorado: Effective on April 14, 2014, requires well production facilities and natural gas compression station owners/operators to insp ect 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 am ount of fugitive VOC emissions identified (i.e., 0-6 tpy - one-time, 6-12 tpy -annua lly, 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 emissi ons 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 horizont al hydraulic fracturing general permits for facilities that emit less than 1 ton per year of any toxic air c ontaminant (not including HAP emitting sources that are subject to MACT HH). Operators are required to develop and implement a site-specific LDAR program for an cillary equipment (e.g. vent, compressor, PRD, flange, etc.) that requires mon itoring using a FLIR camera or Me thod 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-we ll oil and gas producti on 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 st ations with fugitive emissions greater than or equal to 4 tons per year of VOC and requires ow ner/operators to develop and implement an LDAR protocol by January 1, 2017. Fugitive emissions m onitoring can be conducted using a combination of Method 21, OGI, other instrument based tech nologies, or audio-vi sual-olfactory (AVO) inspections. However, an LDAR protocol consis ting of only AVO inspections does not meet the requirements of the rule - at l east 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 Envir onmental Quality approved a “General Approval

47 Colorado regulations available at https://www.colorado.gov/pacific/s ites/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 throu ghput of crude oil and c ondensate combined that is greater than 25,000 barrels. Th e monitoring can be performed using Method 21 (leak definition of 500 ppm), a tunable diode laser abso rption spectroscopy or an IR camera. 50



### Based on the above information, we determined that well sites in these st ates 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 ne w natural gas well completions, both conventional and fractured were covered by leak regulations in thes e 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 th e total number of new natural gas well completions, both conventional and hydraulically fractured in 2012, and used to es timate the total number of new natural gas completions, both conve ntional and hydraulically fractur ed 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 tota ls to estimate the number of new natural gas production well sites. The projected number of new natural gas well s ites was estimated to be 5,518 in 2020. Because the requirements have impacts annually, our projected activ ity 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 assume d 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 numbe r of new oil production we ll sites was determined to be 16,142 in 2012. An annual growth rate of 0.32 pe rcent, which was determined from the NEMS data, was applied to the total number of new oil well completions, both conven tional 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 regul ations, 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. Th e projected number of new oil well sites was estimated to be 16,562 in 2020. Because the re quirements have impacts annually, our projected activity for year 2025 was developed to reflect th e impacts of the rule from 2020 through 2025, or 100,175 well sites in 2025. This approach was used to support the re gulatory impacts assessm ent 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 o il 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 Inventor y. 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 st ations, but it does list th e average number of compressors in the gas production section. It was assu med that this average of 4.5 compressors for gas production facilities is applicable to gathering and boosting stations. Ther efore, using the total number of compressors in the GHG Inventory, the number of gath ering and boosting stations was estimated to be 8,015. To estimate the number of new gathering and boostin g 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 gatheri ng 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 suppor t 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 faci lities was estimated by reviewing the annual number of facilities from the year 1990 to 2012 estim ated in the GHG Inventory and determining the rate of change in the number of these facilities over this peri od. For all the years, th e annual number of new
transmission stations was determined to be 24 and th e annual change in storage facilities was determined to be 16. The average change for the last 10 years was also review ed 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 th e number of new transmission and storage stations from the years 1990 to 2012, it is assumed that the 10-y ear average change represents a better estimate of the current growth of the transmissi on and storage segment, therefore it will be assumed
that there will 6 new transmission sta tions and 15 new storage stations e ach year that would be affectedProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 activ ity for year 2025 was developed to reflect the impacts of the rule from 2020 through 2025. This approach was used to suppor t the regulatory impact s assessment process to reflect rule impacts from th e effective date through 2025.

5.3.3 Emission Estimates The nationwide emissions were calculated using th e 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 boosti ng 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 CH 4 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 410Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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, a nd connectors, are a significant source of CH 4 

### , VOC and HAP emissions from oil and natural gas facilities. Previously, during development of th e 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 producti on, gathering and boosting, and tran smission and storage segments. However, we noted that we would c ontinue to review available data a nd 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 detect or, flow measurement devices). In addition to EPA Met hod 21 analyzers, several studies c onducted fugitive emission surveys using OGI in conjunction with portable Method 21 analyzers and ga s chromatograph equipment to measure individual VOC and HAP compounds. These stud ies 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 CH 4 

### 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 concentr ation 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 tec hnology 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 filteri ng and an array of IR detectors to visualize the IR absorption of hydrocarbons and other gaseous co mpounds. As the gas absorbs radiant energy at the
same waveband that the filter transm its 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 fugitiv e emissions when the technology is us ed appropriately. Several studies in the white paper estimated that OGI can m onitor 1,875-2,100 components per hour. In comparison, the average screening rate using a hand-held toxic va por analyzers (TVA) or OVA is roughly 700 componentsProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 co mponents 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 natu ral gas facilities when co mpared to using a handheld TVA or OVA. Another study in the white paper analyzed 4,293 leak de tection surveys completed for the oil and gas industry using OGI system s 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 ar e found are repaired and the recovered CH 4 

### 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 CH 4 

### and VOC emissions from fugitive emissions components were identified: a fugitive emissions m onitoring 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 m onitoring 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 technologi es are currently used by industry to reduce fugitive emissions from the produc tion segment in the oil a nd 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 a nd 10,000 ppm. For the OGI monitoring analysis, we conclude that any vi sible emissions that are imaged by the OGI instrument is a fugitive emission. Proper operation of the OGI instrument is cr itical for finding fugitive emissions; therefore, several operating procedures, such as daily verifi cation 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 eval uation 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 f acilities) involves the deve lopment of a fugitiveProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### emissions monitoring plan. Under this option, the monitoring is c onducted using OGI. The company may use a corporate-wide monitoring plan that covers th e collection of fugitive emissions components at well sites or compressor stations corpor ate-wide in conjunction with a plan that is site-specific to each collection of fugitive emissions components at well site s 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 em issions components, such as connectors, open-ended lines/valves, pressure relief devi ces, closed vent systems, compresso rs, 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 su rveys must be capable of imaging gas that is half methane and half propane at a concentr ation 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 1 0,000 ppm are generally detectib le using OGI with proper monitoring and operating pract ices. 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 opera tor 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 anal ysis, 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 re paired during the monitoring survey, the operator must repair the component within 15 days of findi ng fugitive emissions. For this resurvey, the operator may use either OGI or Method 21 to confirm that th e component is no longer emitted fugitive emissions. When OGI is used for the resurvey, no visible emi ssions indicate that the fugitive emissions component has been repaired. When Method 21 is used for the re survey, 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 reducti ons from OGI monitoring and repair varied from 40 to 99 percent. The data from these studies are based on the gathering ofProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### individual OGI surveys at various oi l and natural gas segment sites. The variation in the percent reductions from these OGI surveys generally depended on whet her 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 in formation on the potential emission reductions from the implementation of an annual, se miannual, quarterly or monthly OGI monitoring and repair program. A report was found after the publicati on of the white paper from the Colorado Air Quality
Control Commission 51 

### which estimated 40 percent reducti on 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 quarter ly 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 grea ter than 50 tpy (> 50 tpy).
From the review of the studies in the white pape r 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 an alysis, we estimated emissions reductions for the OGI monitoring frequency options (annual, semiannua l and quarterly) using the estimated emission reductions from Colorado’s Economic Impact Analys is 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 monito ring program in combination with a repair program can reduce fugitive CH 4 

### and VOC emissions from these segments by 40 percent on an annual frequency, 60 percent on a semiannual frequency and 80 percent on a qua rterly 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 monitori ng and repair plan for the various segments. See tables A-33 through A-60 in Appendix A for detailed calc ulations of emissions, redu ctions, 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### Table 5-13. Nationwide Emission Reductions for OGI Mo nitoring 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

CH 4 VOC CH 4 VOC CH 4 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 mon itoring and repair plan on a company level were estimated using hourly estimates for each of the pl an 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 comp lete at a cost of $231.20Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 estim ated 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 f acilities. 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 tota l of 12 hours to complete at a cost of $1,387. For oil and natural gas production we ll sites, this cost was divided among the total number of well sites owned by a company, which wa s 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 repa ir elements. The costs are based on the following assumptions:

 The cost for OGI monitoring us ing an outside cont ractor was assumed to be $600 for a well production site and $2,300 for a gath ering and boosting station, a tran smission 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 leak 53 

### and 75% are repaired online and 25% are repaired offline.

 Cost to resurvey the repaired components using a Method 21 device that co uld not be fixed during the initial survey based on $2.00 per component. Th is 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 uncontr olled 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. EP A-HQ-OAR-2002-0 037-0180).Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### purchases Method 21 instrumentation (estimated to be $10,800 54 

### ) and is able to perform the resurvey without reta ining contractors.

 Preparation of annual reports was es timated 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 pro duction well sites was calculated by summing up the costs for reading the rule, development of fugitive emissions monitoring plan, initial activities planning, notif ication of initial complian ce status, and purchase of a Method 21 instrumentation. The total capital cost of these activities was calcu lated to be $17,620 per company. Assuming that each company owns and operates 22 well sites 55 

### , the capital cost per well site was estimated to be $801. For gathering and boosting, transmission and storage compressor stati ons 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 instru mentation was calculated to be $16,407 per facility.
For all oil and natural gas segments, the annual co st includes; subsequentactivities planning, OGI survey, cost of repair of fugitiv e emissions found, resurvey of repa ired components, preparation and submittal of an annual report, and the amortized capita l cost over 8 years at 7 percent interest. For our analysis we calculated th e 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 pres ent the analysis for the estimate d annual cost of implementing an OGI monitoring and repair program for oil and natu ral gas production well sites, gathering and boosting, transmission and storage compressor stations fo r the respective OGI monitoring frequencies.
The cost per ton of emissions re duced was calculated using two se parate methods. The first method allocated all of the costs to each pol lutant separately (single-pollutant approach) using representative unit costs for each control option. The second method allo cates the annual cost among the pollutants (multipollutant approach) that a gi ven technology reduced (i.e., CH 4 

### 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 CH 4 

### and VOC are equal; and therefore the prorat ion of the annual cost was divided equally and applied to the CH 4 

### 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 Equi pment Leaks, Decembe r 21, 2011. EPA-HQOAR-2002-0037-0180
55 The number of well sites owned and op erated by companies was calculated us ing data from the Fort Worth study.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 CH 4 

### and VOC for the various options fo r oil and natural gas production we ll 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 a nd 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 CH 4 

### and VOC for the three OGI monitori ng 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 pol lutants. Tables 5-17, 5-18 and 5- 19 present a summary of the capital and annual costs, and the cost of control for CH 4 

### and VOC using the multi-pollutant method (i.e., 50 percent of the cost attributed to methane and 50 per cent of the cost attributed to VOC). See Tables A-33 through A-60 in Appendix A for detail on the emissions, re ductions and cost of cont rol calculations for the various options for each segment.
5.4.2.4 Secondary Impacts
No secondary gaseous pollutant emissions or wa stewater are generated during the monitoring and repair of fugitive emissions components. There are some emissions that woul d be generated by the IR camera monitoring contractors with re spect to driving to and from the site for the fugitive emissions survey however, these emissions cannot be quantified be cause there is no data rela ted 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 monito ring program would be minimal.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document75Table 5-14.Summary of the Model Plant Cost of Control for the Annual OGI Monitoring Option -Single-PollutantModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOCNatural Gas ProductionWell Sited1.82 0.50 $801 $1,329 $908 $732 $2,633 $500 $1,799Oil Production Well Sited0.44 0.12 $801 $1,329 $1,228 $3,055 $10,992 $2,824 $10,158Well Site Program Weighted Averageh$2,475 $8,903 $2,243 $8,069Gathering & BoostingStatione14.1 3.9 $16,407 $10,124 $6,865 $720 $2,591 $488 $1,757Transmission Stationf24.9 0.7 $16,407 $10,049 $4,882 $403 $14,554 $403 $14,554Storage Facilityg65.8 1.8 $16,407 $13,634 $15 $207 $7,491 $207 $7,491Compressor Stations Program Weighted Averageh$686 $3,110 $471 $2,338a. 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 divided between anaverage of 22 well sites per company. Thecapital cost for the gathering and boosting, transmission and storage segments includes the cost of implementing themonitoring program of $16,407.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 8years at 7% interest.e. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $7,376 and amortization of thecapital cost over 8 years at 7%interest.f. Annual cost for transmission station includes annual monitoring and repair cost of $7,301 and amortization of the capital cost over 8 years at 7% interest.g. Annual cost for storage facilities includes annual monitoring and repair cost of $10,866and amortization of the capital costover 8 years at 7% interest.h.The weighted average for the segments were calculated using the2020 activity counts of 5518 gas well sites, 16562 oil well sites, 259 G&B stations, 6transmission stations and 15 storage facilities.Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the result of equipmentleaks was not estimated for the transmission and storage segment.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document76Table 5-15.Summary of the Model Plant Cost of Control for theSemiannual OGI MonitoringOption -Single-PollutantModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOCNatural Gas ProductionWell Sited2.72 0.76 $801 $2,230 $1,599 $819 $2,945 $587$2,111Oil Production WellSited0.65 0.18 $801 $2,230 $2,079 $3,417 $12,294 $3,186$11,460Well Site Program Weighted Averageh$2,768 $9,958 $2,536$9,124Gathering & BoostingStatione21.1 5.9 $16,407 $15,881 $10,993 $753 $2,710 $521 $1,876Transmission Stationf37.4 1.0 $16,407 $15,732 $7,982 $420 $15,190 $420 $15,190Storage Facilityg98.7 2.7 $16,407 $22,902 $2,473 $232 $8,388 $232 $8,388Compressor Stations Program Weighted Averageh$718 $3,281 $504 $2,510a. 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 divided between anaverage of 22 well sites per company. Thecapital cost for the gathering and boosting, transmission and storage segments includes the cost of implementing themonitoring program of $16,407.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 8years at 7% interest.e. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $13 133 and amortization of the capital cost over 8 years at 7%interest.f. Annual cost for transmission station includes annual monitoring and repair cost of $12,984 and amortization of the capital cost over 8 years at 7% interest.g. Annual cost for storage facilities includes annual monitoring and repair cost of $20,154 and amortization of the capital cost over 8 years at 7% interest.h.The weighted average for the segments were calculated using the2020 activity counts of 5518 gas well sites, 16562 oil well sites, 259 G&B stations, 6transmission stations and 15 storage facilities.Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the result of equipmentleaks was not estimated for the transmission and storage segment.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document77Table 5-16.Summary of the Model Plant Cost of Control for theQuarterly OGI MonitoringOption -Single-PollutantModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOCNatural Gas ProductionWell Sited3.63 1.01 $801 $4,031 $3,190 $1,110 $3,994 $878 $3,160Oil Production Well Sited0.87 0.24 $801 $4,031 $3,830 $4,634 $16,669 $4,402 $15,836Well Site Program Weighted Averageh$3,753 $13,502 $3,521 $12,668Gathering & BoostingStatione28.1 7.8 $16,407 $27,396 $20,879 $974 $3,506 $743 $2,672Transmission Stationf49.9 1.4 $16,407 $27,097 $16,765 $543 $19,623 $336 $12,140Storage Facilityg131.5 3.6 $16,407 $41,437 $14,199 $315 $11,383 $108 $3,901Compressor Stations Program Weighted Averageh$930 $4,273 $715 $3,502a. 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 between an averageof 22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost of implementing themonitoring program of $16,407.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 8years at 7% interest.e. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $24,649 and amortization of the capital cost over 8 years at 7%interest.f. Annual cost for transmission station includes annual monitoring and repair cost of $24,350 and amortization of the capital cost over 8 years at 7% interest.g. Annual cost for storage facilities includes annual monitoring and repair cost of $38,689 and amortization of the capital cost over 8 years at 7% interest.h.The weighted average for the segments were calculated using the2020 activity counts of 5518 gas well sites, 16562 oil well sites, 259 G&B stations, 6transmission stations and 15 storage facilities.Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the result of equipmentleaks was not estimated for the transmission and storage segment.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document78Table 5-17.Summary of the Model Plant Cost of Control for theAnnual OGI Monitoring Option- Multi-Pollutant MethodModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOCNatural Gas ProductionWell Sited1.82 0.50 $801 $1,329 $908 $366 $1,317 $250 $900Oil Production Well Sited0.44 0.12 $801 $1,329 $1,228 $1,528 $5,496 $1,412 $5,079Well Site Program Weighted Averageh$1,237 $4,451 $1,121 $4,035Gathering & BoostingStatione14.1 3.9 $16,407 $10,124 $6,865 $360 $1,295 $244 $878Transmission Stationf24.9 0.7 $16,407 $10,049 $4,882 $201 $7,277 $201 $7,277Storage Facilityg65.8 1.8 $16,407 $13,634 $15 $104 $3,745 $104 $3,745Compressor Stations Program Weighted Averageh$343 $1,555 $236 $1,169a. 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 divided between anaverage of 22 well sites per company. Thecapital cost for the gathering and boosting, transmission and storage segments includes the cost of implementing themonitoring program of $16,407.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 8years at 7% interest.e. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $7,376 and amortization of thecapital cost over 8 years at 7%interest.f. Annual cost for transmission station includes annual monitoring and repair cost of $7,301 and amortization of the capital cost over 8 years at 7% interest.g. Annual cost for storage facilities includes annual monitoring and repair cost of $10,866and amortization of the capital costover 8 years at 7% interest.h.The weighted average for the segments were calculated using the2020 activity counts of 5518 gas well sites, 16562 oil well sites, 259 G&B stations, 6transmission stations and 15 storage facilities.Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the result of equipmentleaks was not estimated for the transmission and storage segment.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document79Table 5-18.Summary of the Model Plant Cost of Control for the Semiannual OGI Monitoring Option - Multi-Pollutant MethodModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOCNatural Gas ProductionWell Sited2.72 0.76 $801 $2,230 $1,599 $409 $1,473 $293 $1,056Oil Production Well Sited0.65 0.18 $801 $2,230 $2,079 $1,709 $6,147 $1,593 $5,730Well Site Program Weighted Averageh$1,384 $4,979 $1,268 $4,562Gathering & BoostingStatione21.1 5.9 $16,407 $15,881 $10,993 $377 $1,355 $261 $938Transmission Stationf37.4 1.0 $16,407 $15,732 $7,982 $210 $7,595 $210 $7,595Storage Facilityg98.7 2.7 $16,407 $22,902 $2,473 $116 $4,194 $116 $4,194Compressor Stations Program Weighted Averageh$359 $1,641 $252 $1,255a. 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 divided between anaverage of 22 well sites per company. Thecapital cost for the gathering and boosting, transmission and storage segments includes the cost of implementing themonitoring program of $16,407.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 8years at 7% interest.e. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $13 133 and amortization of the capital cost over 8 years at 7%interest.f. Annual cost for transmission station includes annual monitoring and repair cost of $12,984 and amortization of the capital cost over 8 years at 7% interest.g. Annual cost for storage facilities includes annual monitoring and repair cost of $20,154 and amortization of the capital cost over 8 years at 7% interest.h.The weighted average for the segments were calculated using the2020 activity counts of 5518 gas well sites, 16,562 oil well sites, 259 G&B stations, 6transmission stations and 15 storage facilities.Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the result of equipmentleaks was not estimated for the transmission and storage segment.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document80Table 5-19.Summary of the Model Plant Cost of Control for the Quarterly OGI Monitoring Option - Multi-Pollutant MethodModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOCNatural Gas ProductionWell Sited3.63 1.01 $801 $4,031 $3,190 $555 $1,997 $439 $1,580Oil Production WellSited0.87 0.24 $801 $4,031 $3,830 $2,317 $8,335 $2,201 $7,918Well Site Program Weighted Averageh$1,877 $6,751 $1,761 $6,334Gathering & BoostingStatione28.1 7.8 $16,407 $27,396 $20,879 $487 $1,753 $371 $1,336Transmission Stationf49.9 1.4 $16,407 $27,097 $16,765 $272 $9,812 $272 $9,812Storage Facilityg131.5 3.6 $16,407 $41,437 $14,199 $158 $5,692 $158 $5,692Compressor Stations Program Weighted Averageh$465 $2,136 $358 $1,751a. 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 between an averageof 22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the cost of implementing themonitoring program of $16,407.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 8years at 7% interest.e. Annual cost for gathering and boosting stations includes annual monitoring and repair cost of $24,649 and amortization of the capital cost over 8 years at 7%interest.f. Annual cost for transmission station includes annual monitoring and repair cost of $24,350 and amortization of the capital cost over 8 years at 7% interest.g. Annual cost for storage facilities includes annual monitoring and repair cost of $38,689 and amortization of the capital cost over 8 years at 7% interest.h.The weighted average for the segments were calculated using the2020 activity counts of 5518 gas well sites, 16562 oil well sites, 259 G&B stations, 6transmission 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 result of equipmentleaks was not estimated for the transmission and storage segment.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 th e fugitive emissions components at well sites and compressor stations,
we have evaluated Method 21 as an option to allow comm ent 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 de scribed above. The Method 21 monitoring includes the development of fugitive emissions monitoring pl an, surveying using Method 21 instrumentation, resurvey of repaired components and the preparation and submittal of an annua l 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. Th e monitoring plan must include insp ection of the collection of fugitive emissions components, such as connectors, open-ended lines/valves, pressure reli ef 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 evid ence 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 Met hod 21 to ensure the fugitive emissions are no longer
visible or is below a leak repair threshold of the plan. For our anal ysis, we evaluated th ree 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 fr equency of the monitoring/repair of the components as well as the repair th reshold 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 Organi c Chemical Manufacturing Industry (SOCMI) and Petroleum Refining Industry. Th is data was used to estimate the uncontrolled emissions (i.e., baseline emissions0 and the corr esponding emission reduction pe rcentages that could potentially be achieved for each of the leak de finitions (500 ppm, 2,500 ppm, 10,000 ppm) and monitoring frequencies (annual, semiannual, quar terly). Using this information we calculated an expected emissionsProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 estima ted nationwide baseline emissions for the various options for a Method 21 monitoring a nd 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

CH 4 VOC CH 4 VOC CH 4 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 61Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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Segment Number of New Facilities Annual Monitoring (tpy) a Semiannual Monitoring (tpy) a Quarterly Monitoring (tpy) a

CH 4 VOC CH 4 VOC CH 4 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 64Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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Segment Number of New Facilities Annual Monitoring (tpy) a Semiannual Monitoring (tpy) a Quarterly Monitoring (tpy) a

CH 4 VOC CH 4 VOC CH 4 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 th e 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 comp lete 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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###  Initial activities planning are estim ated 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 f acilities. For companies that own and operate production we ll sites, the cost for notifica tion of compliance status was estimated to be $58 for 22 well site s 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 tota l of 12 hours to complete at a cost of $1,387. For oil and natural gas production we ll sites, this cost was divided among the total number of well sites owned by a company, which wa s 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 repa ir 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 usi ng a M21 monitoring device, and $925, assuming 2 people and 8 hours per person to survey a gather ing 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 defini tion 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, 1 2.25 percent at a leak definition of 2,500 ppm and 13.53 percent at a leak definition of 500 ppm. Th e leak percentages were calculated using the baseline SOCMI emission rate (0.00 597 kg/hr/source) and the average leak rate to fraction leaking equations for 500, 2,500 and 10,000 ppmv leak definiti on 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 th e 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, Decembe r 21, 2011. EP A-HQ-OAR-2002 -0037-0180.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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###  Cost for resurvey of components after re pair based on $2.00 per component resurveyed.

 Preparation of annual reports was es timated 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 pro duction 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 ru le, development of fugitive emissions monitoring plan, initial activities planning, and no tification of initial co mpliance status was calculated to be $30,907 per facility.
For all segments, the annual cost includes; subs equent activities planning, Method 21 survey, cost of repair of fugitive emissions found, resurvey of the repaired component s, preparation and submittal of an annual report, and the amortized capita l cost over 8 years at 7 percen t interest. For our analysis we
calculated the annual cost for annual, semiannual and quarterly Met hod 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 monito ring and repair program under the nine sub-option combinations of monito ring frequency and re pair threshold.
The cost per ton of emissions re duced was calculated using two se parate methods. The first method attributes all of the costs to each pollutant separate ly (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., CH 4 

### 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 CH 4 

### and VOC are equal; and therefore the alloca tion of the annual cost was divided equally and applied to the CH 4 

### and VOC reductions.

Based on estimated emissions reductions and th e estimated cost for implementing a Method 21 fugitive emissions monitoring and repair program at the affected facilities, we calculated a cost of control
for CH 4 

### 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 cal culated the weighted average cost of control for all well sites and all compressor stati ons under each of the monito ring and repair plan subProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 CH 4 

### and VOC for the Method 21 plan monitoring opt ions (i.e., annual, se miannual and quarterly, respectively) and the three repair thresholds (i.e., 10,000 ppm, 2,500 ppm a nd 500 ppm, respectively) based on 100 percent of the cost bein g attributed to the individual pol lutants. Tables 5-23, 5-24 and 5-25 present a summary of the capital and annua l costs, and the cost of control for CH 4 

### and VOC using the multi-pollutant method (i.e., 50 percent of the cost at tributed 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 analys is for the various sub-options for each segment.
5.4.2.4 Secondary Impacts
No secondary gaseous pollutant emissions or wa stewater 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 contract ors 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 pr ogram would be minimal.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document88Table 5-22. Summary of the Model Plant Cost of Control for the Annual Method 21 Monitoring and Repair Plan Options SinglePollutantModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOC10,000 ppmNatural Gas ProductionWell Sited3.72 1.03 $1,460 $4,020 $3,157 $1,080 $3,885 $848 $3,051Oil Production WellSited0.73 0.20 $1,460 $4,020 $3,813 $5,517 $19,847 $5,233 $18,826Well Site Program Weighted Averageh$4,408 $15,858 $4,137 $14,884Gathering and BoostingStatione28.88.01$30,907$37,203$30,523$1,291$4,644$1,059$3,810Transmission Statione51.1 1.42 $30,907 $37,203 $37,203 $727 $26,284 $727 $26,284Storage Facilitye134.8 3.73 $30,907 $37,203 $37,203 $276 $9,971 $276 $9,971Compressor Station Weighted Average $1,225 $5,393 $1,010 $4,6222,500 ppmNatural Gas ProductionWell Sited4.27 1.19 $1,460 $6,103 $5,113 $1,430 $5,145 $1,198 $4,311Oil Production WellSited1.02 0.28 $1,460 $6,103 $5,866 $5,970 $21,475 $5,738 $20,642Well Site Program Weighted Averageh$4,835 $17,394 $4,603 $16,560Gathering and BoostingStatione33.09.18$30,907$55,860$48,203$1,691$6,083$1,459$5,249Transmission Statione58.6 1.62 $30,907 $55,860 $55,860 $953 $34,427 $953 $34,427Storage Facilitye154.6 4.28 $30,907 $55,860 $55,860 $361 $13,060 $361 $13,060Compressor Station Weighted Average $1,604 $7,064 $1,390 $6,293Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document89Model PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOC500 ppmNatural Gas ProductionWell Sited4.45 1.24 $1,460 $6,437 $5,406 $1,447 $5,206 $1,215 $4,372Oil Production WellSited1.07 0.30 $1,460 $6,437 $6,190 $6,040 $21,728 $5,808 $20,894Well Site Program Weighted Averageh$4,892 $17,599 $4,660 $16,765Gathering and BoostingStatione34.4 9.57 $30,907 $60,973 $52,990 $1,770 $6,369 $1,539 $5,535Transmission Statione61.1 1.69 $30,907 $60,973 $60,973 $998 $36,045 $998 $36,045Storage Facilitye161.1 4.46 $30,907 $60,973 $60,973 $378 $13,673 $378 $13,673Compressor Station Weighted Average $1,679 $7,396 $1,465 $6,625a. Assumes 82% reduction with the implementation of repair threshold of 10,000 ppm, 94% reduction for 2,500 ppm and 98% for 500ppm for an annual method 21monitoring.b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divided between an average of22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the costof implementing the monitoringprogram of $30,907.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 for2,500 ppm and $6,193 for 500 ppmand 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 andrepair cost of 32,027 for 10,000 ppmrepair threshold, $50,685 for 2,500 ppm and $55,973 for 500 ppm and amortization of the capital cost over 8 years at 7% interest.Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the result of equipmentleaks was not estimated for the transmission or storage segment.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document90Table 5-23. Summary of the Model Plant Cost of Control forthe Semiannual Method 21 Monitoring and Repair Plan OptionsSingle-PollutantModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOC10,000 ppmNatural Gas ProductionWell Sited3.27 0.91 $1,460 $4,482 $3,725 $1,371 $4,934 $1,140 $4,100Oil Production WellSited0.78 0.22 $1,460 $4,482 $4,301 $5,724 $20,593 $5,493 $19,759Well Site Program Weighted Averageh$4,637 $16,680 $4,405 $15,846Gathering and BoostingStatione25.37.03$30,907$38,128$32,263$1,507$5,421$1,275$4,587Transmission Statione44.9 1.24 $30,907 $38,128 $38,128 $849 $30,679 $849 $30,679Storage Facilitye118.4 3.28 $30,907 $38,128 $38,128 $322 $11,638 $322 $11,638Compressor Station Weighted Average $1,429 $6,295 $1,215 $5,5242,500 ppmNatural Gas ProductionWell Sited4.18 1.16 $1,460 $6,565 $5,597 $1,572 $5,655 $1,340 $4,821Oil Production WellSited1.00 0.28 $1,460 $6,565 $6,333 $6,562 $23,605 $6,330 $22,771Well Site Program Weighted Averageh$5,315 $19,119 $5,083 $18,285Gathering and BoostingStatione32.38.99$30,907$56,785$49,291$1,756$6,318$1,525$5,485Transmission Statione57.4 1.59 $30,907 $56,785 $56,785 $990 $35,758 $990 $35,758Storage Facilitye151.3 4.19 $30,907 $56,785 $56,785 $375 $13,565 $375 $13,565Compressor Station Weighted Average $1,666 $7,337 $1,452 $6,566500 ppmProposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document91Model PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOCNatural Gas ProductionWell Sited4.40 1.22 $1,460 $6,899 $5,879 $1,567 $5,637 $1,335 $4,803Oil Production WellSited1.05 0.29 $1,460 $6,899 $6,655 $6,540 $23,529 $6,309 $22,695Well Site Program Weighted Averageh$5,298 $19,058 $5,066 $18,224Gathering and BoostingStatione34.1 9.48 $30,907 $61,898 $53,996 $1,816 $6,532 $1,584 $5,698Transmission Statione60.5 1.67 $30,907 $61,898 $61,898 $1,023 $36,969 $1,023 $36,969Storage Facilitye159.5 4.41 $30,907 $61,898 $61,898 $388 $14,024 $388 $14,024Compressor Station Weighted Average $1,722 $7,586 $1,508 $6,814a. Assumes 72% reduction with the implementation of repair threshold of 10,000 ppm, 92% reduction for 2,500 ppm and 97% for 500ppm for an annual method 21monitoring.b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divided between an average of22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the costof implementing the monitoringprogram of $30,907.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 for2,500 ppm and $6,655 for 500 ppmand 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 andrepair cost of $32,952 for 10,000 ppmrepair threshold, $51,609 for 2,500 ppm and $61,8988 for 500 ppm and amortization of the capital cost over 8 years at 7% interest.Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the result of equipmentleaks was not estimated for the transmission or storage segment.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document92Table 5-24. Summary of the Model Plant Cost of Control for theQuarterly Method 21 Monitoring and Repair Plan Options SinglePollutantModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOC10,000 ppmNatural Gas ProductionWell Sited3.04 0.85 $1,460 $5,407 $4,702 $1,778 $6,396 $1,546 $5,562Oil Production WellSited0.36 0.20 $1,460 $5,407 $5,238 $15,066 $26,696 $14,596 $25,862Well Site Program Weighted Averageh$11,746 $21,623 $11,335 $20,789Gathering and BoostingStation23.56.55$30,907$39,978$34,519$1,698$6,108$1,466$5,274Transmission Station 41.8 1.16 $30,907 $39,978 $39,978 $957 $34,568 $957 $34,568Storage Facility 110.2 3.05 $30,907 $39,978$39,978 $363 $13,113 $363 $13,113Compressor Station Weighted Average $1,610 $7,093 $1,396 $6,3222,500 ppmNatural Gas ProductionWell Sited4.04 1.12 $1,460 $7,490 $6,553 $1,854 $6,669 $1,622 $5,835Oil Production WellSited0.97 0.27 $1,460 $7,490 $7,265 $7,738 $27,838 $7,506 $27,004Well Site Program Weighted Averageh$6,268 $22,548 $6,036 $21,714Gathering and BoostingStation31.38.69$30,907$58,635$51,385$1,875$6,744$1,643$5,910Transmission Station 55.5 1.54 $30,907 $58,635 $58,635 $1,056 $38,168 $1,056 $38,168Storage Facility 146.3 4.05 $30,907 $58,635$58,635 $401 $14,479 $401 $14,479Compressor Station Weighted Average $1,778 $7,832 $1,564 $7,060500 ppmProposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document93Model PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOCNatural Gas ProductionWell Sited4.27 1.19 $1,460 $7,824 $6,835 $1,834 $6,597 $1,602 $5,763Oil Production WellSited1.02 0.28 $1,460 $7,824 $7,587 $7,654 $27,534 $7,422 $26,700Well Site Program Weighted Averageh$6,199 $22,302 $5,968 $21,468Gathering and BoostingStation33.0 9.18 $30,907 $63,747 $56,090 $1,930 $6,942 $1,698 $6,108Transmission Station 58.6 1.62 $30,907 $63,747 $63,747 $1,087 $39,288 $1,087 $39,288Storage Facility 154.6 4.28 $30,907 $63,747$63,747 $412 $14,904 $412 $14,904Compressor Station Weighted Average $1,830 $8,062 $1,616 $7,290a. Assumes 67% reduction with the implementation of repair threshold of 10,000 ppm, 89% reduction for 2,500 ppm and 94% for 500ppm for an annual method 21monitoring.b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divided between an average of22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the costof implementing the monitoringprogram of $30,907.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 for2,500 ppm and $7,580 for 500 ppmand 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 andrepair cost of $34,802 for 10,000 ppmrepair threshold, $53,459 for 2,500 ppm and $63,747 for 500 ppm and amortization of the capital cost over 8 years at 7% interest.Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the result of equipmentleaks was not estimated for the transmission or storage segment.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document94Table 5-25. Summary of the Model Plant Cost of Control for the Annual Method 21 Monitoring and Repair Plan Options MultiPollutantModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOC10,000 ppmNatural Gas ProductionWell Sited3.72 1.03 $1,460 $4,020 $3,157 $540 $1,943 $424 $1,526Oil Production WellSited0.73 0.20 $1,460 $4,020 $3,813 $2,758 $9,924 $2,617 $9,413Well Site Program Weighted Averageh$2,204 $7,929 $2,069 $7,442Gathering and BoostingStation28.8 8.01 $30,907 $37,203 $30,523 $646 $2,322 $530 $1,905Transmission Station 51.1 1.42 $30,907 $37,203 $37,203 $364 $13,142 $364 $13,142Storage Facility 134.8 3.73 $30,907$37,203 $37,203 $138 $4,985 $138 $4,985Compressor Station Weighted Average $612 $2,697 $505 $2,3112,500 ppmNatural Gas ProductionWell Sited4.27 1.19 $1,460 $6,103 $5,113 $715$2,573$599$2,156Oil Production WellSited1.02 0.28 $1,460 $6,103 $5,866 $2,985$10,738$2,869$10,321Well Site Program Weighted Averageh$2,418$8,697$2,302$8,280Gathering and BoostingStation33.0 9.18 $30,907 $55,860 $48,203 $845 $3,042 $730 $2,625Transmission Station 58.6 1.62 $30,907 $55,860 $55,860 $476 $17,214 $476 $17,214Storage Facility 154.6 4.28 $30,907$55,860 $55,860 $181 $6,530 $181 $6,530Compressor Station Weighted Average $802 $3,532 $695 $3,147Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document95Model PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOC500 ppmNatural Gas ProductionWell Sited4.45 1.24 $1,460 $6,437 $5,406 $724 $2,603 $608 $2,186Oil Production WellSited1.07 0.30 $1,460 $6,437 $6,190 $3,020 $10,864 $2,904 $10,447Well Site Program Weighted Averageh$2,446 $8,799 $2,330 $8,383Gathering and BoostingStation34.4 9.57 $30,907 $60,973 $52,990 $885 $3,185 $769 $2,768Transmission Station 61.1 1.69 $30,907 $60,973 $60,973 $499 $18,022 $499 $18,022Storage Facility 161.1 4.46 $30,907$60,973 $60,973 $189 $6,837 $189 $6,837Compressor Station Weighted Average $840 $3,698 $732 $3,312a. Assumes 82% reduction with the implementation of repair threshold of 10,000 ppm, 94% reduction for 2,500 ppm and 98% for 500ppm for an annual method 21monitoring.b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divided between an average of22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the costof implementing the monitoringprogram of $30,907.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 for2,500 ppm and $6,193 for 500 ppmand 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 andrepair cost of 32,027 for 10,000 ppmrepair threshold, $50,685 for 2,500 ppm and $55,973 for 500 ppm and amortization of the capital cost over 8 years at 7% interest.Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the result of equipmentleaks was not estimated for the transmission or storage segment..Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document96Table 5-26. Summary of the Model Plant Cost of Control for theSemiannual Method 21 Monitoring and Repair Plan Options MultiPollutantModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOC10,000 ppmNatural Gas ProductionWell Sited3.27 0.91 $1,460 $4,482 $3,725 $686 $2,467 $570 $2,050Oil Production WellSited0.78 0.22 $1,460 $4,482 $4,301 $2,862 $10,297 $2,746 $9,880Well Site Program Weighted Averageh$2,318 $8,340 $2,202 $7,923Gathering and BoostingStation25.3 7.03 $30,907 $38,128 $32,263 $753 $2,710 $638 $2,293Transmission Station 44.9 1.24 $30,907 $38,128 $38,128 $425 $15,339 $425 $15,339Storage Facility 118.4 3.28 $30,907$38,128 $38,128 $161 $5,819 $161 $5,819Compressor Station Weighted Average $715 $3,148 $607 $2,7622,500 ppmNatural Gas ProductionWell Sited4.18 1.16 $1,460 $6,565 $5,597 $786 $2,828 $670 $2,411Oil Production WellSited1.00 0.28 $1,460 $6,565 $6,333 $3,281 $11,802 $3,165 $11,385Well Site Program Weighted Averageh$2,657 $9,560 $2,541 $9,143Gathering and BoostingStation32.3 8.99 $30,907 $56,785 $49,291 $878 $3,159 $762 $2,742Transmission Station 57.4 1.59 $30,907 $56,785 $56,785 $495 $17,879 $495 $17,879Storage Facility 151.3 4.19 $30,907$56,785 $56,785 $188 $6,782 $188 $6,782Compressor Station Weighted Average $833 $3,669 $726 $3,283Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document97Model PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOC500 ppmNatural Gas ProductionWell Sited4.40 1.22 $1,460 $6,899 $5,879 $783 $2,819 $668 $2,402Oil Production WellSited1.05 0.29 $1,460 $6,899 $6,655 $3,270 $11,764 $3,154 $11,348Well Site Program Weighted Averageh$2,649 $9,529 $2,533 $9,112Gathering and BoostingStation34.1 9.48 $30,907 $61,898 $53,996 $908 $3,266 $792 $2,849Transmission Station 60.5 1.67 $30,907 $61,898 $61,898 $512 $18,484 $512 $18,484Storage Facility 159.5 4.41 $30,907$61,898 $61,898 $194 $7,012 $194 $7,012Compressor Station Weighted Average $861 $3,793 $754 $3,407a. Assumes 72% reduction with the implementation of repair threshold of 10,000 ppm, 92% reduction for 2,500 ppm and 97% for 500ppm for an annual method 21monitoring.b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divided between an average of22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the costof implementing the monitoringprogram of $30,907.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 for2,500 ppm and $6,655 for 500 ppmand 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 andrepair cost of $32,952 for 10,000 ppmrepair threshold, $51,609 for 2,500 ppm and $61,8988 for 500 ppm and amortization of the capital cost over 8 years at 7% interest.Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of natural gas as the result of equipmentleaks was not estimated for the transmission or storage segment.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document98Table 5-27. Summary of the Model Plant Cost of Control for theQuarterly Method 21 Monitoring and Repair Plan Options MultiPollutantModel PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOC10,000 ppmNatural Gas ProductionWell Sited3.04 0.85 $1,460 $5,407 $4,702 $889 $3,198 $773 $2,781Oil Production WellSited0.36 0.20 $1,460 $5,407 $5,238 $7,533 $13,348 $7,298 $12,931Well Site Program Weighted Averageh$5,873 $10,811 $5,667 $10,394Gathering and BoostingStation23.5 6.55 $30,907 $39,978 $34,519 $849 $3,054 $733 $2,637Transmission Station 41.8 1.16 $30,907 $39,978 $39,978 $478 $17,284 $478 $17,284Storage Facility 110.2 3.05 $30,907$39,978 $39,978 $181 $6,557 $181 $6,557Compressor Station Weighted Average $805 $3,547 $698 $3,1612,500 ppmNatural Gas ProductionWell Sited4.04 1.12 $1,460 $7,490 $6,553 $927 $3,335 $811 $2,918Oil Production WellSited0.97 0.27 $1,460 $7,490 $7,265 $3,869 $13,919 $3,753 $13,502Well Site Program Weighted Averageh$3,134 $11,274 $3,018 $10,857Gathering and BoostingStation31.3 8.69 $30,907 $58,635 $51,385 $937 $3,372 $821 $2,955Transmission Station 55.5 1.54 $30,907 $58,635 $58,635 $528 $19,084 $528 $19,084Storage Facility 146.3 4.05 $30,907$58,635 $58,635 $200 $7,239 $200 $7,239Compressor Station Weighted Average $889 $3,916 $782 $3,530Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document99Model PlantAnnual EmissionReductionsa(tpy)CapitalCostb($)Annual Cost($/year)Cost of Control(without savings)($/ton)Cost of Control(with saving)c($/ton)CH4VOCwithoutsavingswithsavingsCH4VOCCH4VOC500 ppmNatural Gas ProductionWell Sited4.27 1.19 $1,460 $7,824 $6,835 $917 $3,298 $801 $2,881Oil Production WellSited1.02 0.28 $1,460 $7,824 $7,587 $3,827 $13,767 $3,711 $13,350Well Site Program Weighted Averageh$3,100 $11,151 $2,984 $10,734Gathering and BoostingStation33.0 9.18 $30,907 $63,747 $56,090 $965 $3,471 $849 $3,054Transmission Station 58.6 1.62 $30,907 $63,747 $63,747 $544 $19,644 $544 $19,644Storage Facility 154.6 4.28 $30,907$63,747 $63,747 $206 $7,452 $206 $7,452Compressor Station Weighted Average $915 $4,031 $808 $3,645a. Assumes 67% reduction with the implementation of repair threshold of 10,000 ppm, 89% reduction for 2,500 ppm and 94% for 500ppm for an annual method 21monitoring.b. The capital cost for oil and natural gas production well sites includes the cost of implementing the monitoring program of $31,120 divided between an average of22 well sites per company. The capital cost for the gathering and boosting, transmission and storage segments includes the costof implementing the monitoringprogram of $30,907.c. Recovery credits for oil and natural gas production well sites and gathering and boosting stations were calculated assumingnatural gas reductions based CH4reductions, CH4as 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 for2,500 ppm and $7,580 for 500 ppmand 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 andrepair cost of $34,802 for 10,000 ppmrepair 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 the result of equipmentleaks was not estimated for the transmission or storage segment.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### 5.5 Regulatory Options
Monitoring and repair of fugitive emissions com ponents 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 stat ions, 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 m onitoring 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 monitori ng 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 pp m and 500 ppm). The sub-options shown below summarize those possible combinations.

o Regulatory Option 2a -500 - Conducting monito ring 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 th reshold level of 2,500 ppm.

o Regulatory Option 2a -10,000 - Conducting Met hod 21 monitoring and repair on an annual frequency with a repair th reshold level of 10,000 ppm.

o Regulatory Option 2b -500 - C onducting Method 21 monitoring and repair on a semiannual frequency with a repair th reshold level of 500 ppm.

o Regulatory Option 2b -2500 - Conducting Me thod 21 monitoring and repair on a semiannual frequency with a repa ir threshold level of 2,500 ppm.

o Regulatory Option 2b -10,000 - Conducting Me thod 21 monitoring and repair on a semiannual frequency with a repa ir threshold level of 10,000 ppm.

o Regulatory Option 2c -500 - Conducting Method 21 monitoring and repair on a quarterly frequency with a repair th reshold level of 500 ppm.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### o Regulatory Option 2c -2500 - Conducting Method 21 monitoring and repair on a quarterly frequency with a repair th reshold level of 2,500 ppm.

o Regulatory Option 2c -10,000 - Conducting Method 21 monitoring and repair on a quarterly frequency with a repa ir 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 co st of control for well sites (which includes oil and gas production well sites) and compressor stations (whi ch 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 base d on the frequency of OGI monitoring conducted. For Option 1a, based on an annual frequency, the single-pollutant cost of control, with out considering savings for gas recovery was calcu lated to be $2,475 per ton of CH 4 

### 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 CH 4 

### and $4,451 per ton of VOC. Option 1b base d on a semiannual frequency, the singlepollutant cost of control, without considering savings for gas r ecovery was calculated to be $2,768 per ton
of CH 4 

### 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 CH 4 

### and $4,979 per ton of VOC. Option 1c, based on a quarterly frequency, the single-pollu tant cost of control, without c onsidering savings for gas recovery was calculated to be $3,753 per ton of CH 4 

### and $13,502 per ton of VOC. The multi-pollutant cost of control, without consid ering savings for gas recovery was calculated to be $1,877 per ton of CH 4 

### 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 fre quency, the single-pollutant cost of control, considering savings for gas recovery was calculated to be $2,243 per ton of CH 4 

### and $8,069 per ton of VOC. The multi-pollutant cost of control, considering savings for gas re covery was calculated to be $1,121 per ton of CH 4 

### and $4,035 per ton of VOC. Option 1b, based on a semiannual fr equency, the single-pollutant cost of control, without considering savings for gas recove ry was calculated to be $2,536 per ton of CH 4 

### 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 CH 4 

### and $4,562 per ton of VOC. Option 1c, base d on a quarterly frequency, the single-Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### pollutant cost of control, consid ering savings for gas recovery was calculated to be $3,521 per ton of CH 4 

### 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 CH 4 

### and $6,334 per ton of VOC.
Compressor Stations For compressor stations we have three sub-opt ions 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 fo r gas recovery, was calculated to be $686 per ton of CH 4 

### and $3,110 per ton of VOC. The multi-pollutant cost of control, without cons idering savings for gas recovery was calculated to be $343 per ton of CH 4 

### and $1,555 per ton of VOC. Based on a se miannual frequency (option 1b), the single-pollutant cost of control, wi thout consideration of savings for ga s recovery, was calculated to be $718 per ton of CH 4 

### and $3,281 per ton of VOC. The multi-pollutant cost of control, without considering savings for gas recovery was calcu lated to be $359 per ton of CH 4 

### and $1,641per ton of VOC. Based on a quarterly frequency (option 1c), the single-pollutant co st of control, without c onsideration of savings for gas recovery, was calculated to be $930 per ton of CH 4 

### and $4,273 per ton of VOC. The multi-pollutant cost of control, without consider ing savings for gas recovery was cal culated to be $465 per ton of CH 4 

### and $2,136 per ton of VOC.
Because the gas handled by transmission and storag e 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 coul d be considered. Therefore, we cal culated the cost of control for compressor stations considering the gas savings cont ributed by gathering and bos ting stations. Based on an annual frequency (option 1a), the single-pollutant cost of control, with consid eration of savings for gas recovery, was calculated to be $471 per ton of CH 4 

### and $2,338 per ton of VOC. The multi-pollutant cost of control, considering savings for gas reco very was calculated to be $236 per ton of CH 4 

### and $1,169 per ton of VOC. Based on a semiannual frequency (option 1b), the single-pollutant co st of control, with consideration of savings fo r gas recovery, was calculated to be $504 per ton of CH 4 

### and $2,510 per ton of VOC. The multi-pollutant cost of control, consideri ng savings for gas recovery was calculated to be $252 per ton of CH 4 

### and $1,255 per ton of VOC. And based on a qua rterly frequency (option 1c), the singlepollutant cost of control, with consideration of savi ngs for gas recovery, was cal culated to be $715 per ton
of CH 4 

### and $3,502 per ton of VOC. The multi-pollutant co st of control, considering savings for gas recovery was calculated to be $358 per ton of CH 4 

### and $1,751 per ton of VOC.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### We also evaluated the reasonabl eness of the burden to industry for the three options with the respective reductions and costs. We determined that the quarterly mon itoring 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 associ ated costs. Therefore, our analysis of nationwide imp acts considered options 1a (annual monitoring) and 1b (semiannual monitoring) as OGI monitoring and re pair plan options for the NSPS.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document104Table 5-28. Summary of the Cost of Control for SubOptions of Option 1 Based on OGI MonitoringOptionCost of Control(without gas savings)Cost of Control(with gas savings)Single-Pollutant($/ton)Multi-Pollutant($/ton)Single-Pollutant($/ton)Multi-Pollutant($/ton)MethaneVOCMethaneVOCMethaneVOCMethaneVOCWell Sites1a - Annual $2,475 $8,903 $1,237 $4,451 $2,243 $8,069 $1,121 $4,0351b - Semiannual $2,768 $9,958 $1,384 $4,979 $2,536 $9,124 $1,268 $4,5621c - Quarterly $3,753 $13,502 $1,877 $6,751 $3,521 $12,668 $1,761 $6,334Compressor Stations1a - Annual $686 $3,110 $343 $1,555 $471 $2,338 $236 $1,1691b - Semiannual $718 $3,281 $359 $1,641 $504 $2,510 $252 $1,2551c - Quarterly $930 $4,273 $465 $2,136 $715 $3,502 $358 $1,751Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 co st of control for well sites (which includes oil and gas production well sites) and compressor stations (whi ch 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 (a nnual, semiannual and quarter ly) and thre e 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 we ll sites and compressor stations in Table 5-29.
Our analysis of the cost of control for the va rious 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 cont rol 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 cont rol under the single-pollutant met hod (i.e., all cost attributed to methane and VOC individually), and without consider ing gas savings, was determined to range from $4,408 (annual frequency at 10,000 ppm repair threshold) to $6,199 (qua rterly 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 percen t 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-pollu tant method, the cost of control was found to range from $4,137 to $ 5,968 per ton of methane and $1 4,884 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 gath ering 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 cons idering gas savings, was determined to range from $1,225 (annual frequency at 10,000 ppm repair thres hold) to $1,830 (quarterly frequenc y at 500 ppm repair threshold per ton of methane and $5,393 to $8,062 per ton of VOC. U nder the multi-pollutant method, (i.e., 50 percentProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 t on of methane and $2,697 to $4,031 per ton of VOC.
Because the gas handled by transmission and storag e 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 coul d be considered. Therefore, we cal culated the cost of control for compressor stations considering the gas savings c ontributed 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 $3,645 per ton of VOC.
As with OGI monitoring, we also evaluated the reasonableness of the bur den to industry for the three options with the respective re ductions and costs. We determined that the quarterly monitoring frequency was too costly for most segments and would be considered overly burdensome given the
additional level of emissions reduction s. In addition, we determined that the 500 ppm leak repair threshold was too costly for these segments and have eliminated this option from each of the monitoring frequencies. Annual and semiannual monitoring appeared to have reasonable associ ated costs. Therefore, our analysis of nationwide impact s considered the two sub-options for 2a (annual monitoring at the 10,000 and 2,500 ppm repair thresholds) an d the two sub-options for option 2b (semiannual monitoring at the 10,000 and 2,500 ppm repair thresholds) as viable Method 21 monitoring a nd repair plan options for the
NSPS.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document107Table 5-29. Summary of the Cost of Control for Sub Options ofOption 2 Based on Method 21 Monitoring and Three RepairThresholdsOptionCost of Control(without gas savings)Cost of Control(with gas savings)Single-Pollutant($/ton)Multi-Pollutant($/ton)Single-Pollutant($/ton)Multi-Pollutant($/ton)MethaneVOCMethaneVOCMethaneVOCMethaneVOCWell Sites2a - Annual, 10,000 ppm $4,408 $15,858 $2,204 $7,929 $4,137 $14,884 $2,069 $7,4422a - Annual, 2,500 ppm $4,835 $17,394 $2,418 $8,697 $4,603 $16,560 $2,302 $8,2802a - Annual, 500 ppm $4,892 $17,599 $2,446 $8,799 $4,660 $16,765 $2,330 $8,3832b - Semiannual, 10,000 ppm $4,637 $16,680 $2,318 $8,340 $4,405 $15,846 $2,202 $7,9232b - Semiannual, 2,500 ppm $5,315 $19,119 $2,657 $9,560 $5,083 $18,285 $2,541 $9,1432b - Semiannual, 500 $5,298 $19,058 $2,649 $9,529 $5,066 $18,224 $2,533 $9,1122c - Quarterly, 10,000 ppm $11,746 $21,623 $5,873 $10,811 $11,335 $20,789 $5,667 $10,3942c - Quarterly, 2,500 ppm $6,268 $22,548 $3,134 $11,274 $6,036 $21,714 $3,018 $10,8572c - Quarterly, 500 ppm $6,199 $22,302 $3,100 $11,151 $5,968 $21,468 $2,984 $10,734Compressor Stations2a - Annual, 10,000 ppm $1,225 $5,393 $612 $2,697 $1,010 $4,622 $505 $2,3112a - Annual, 2,500 ppm $1,604 $7,064 $802 $3,532 $1,390 $6,293 $695 $3,1472a - Annual, 500 ppm $1,679 $7,396 $840 $3,698 $1,465 $6,625 $732 $3,3122b - Semiannual, 10,000 ppm $1,429 $6,295 $715 $3,148 $1,215 $5,524 $607 $2,7622b - Semiannual, 2,500 ppm $1,666 $7,337 $833 $3,669 $1,452 $6,566 $726 $3,2832b - Semiannual, 500 ppm $1,722 $7,586 $861 $3,793 $1,508 $6,814 $754 $3,4072c - Quarterly, 10,000 ppm $1,610 $7,093 $805 $3,547 $1,396 $6,322 $698 $3,1612c - Quarterly, 2,500 ppm $1,778 $7,832 $889 $3,916 $1,564 $7,060 $782 $3,5302c - Quarterly, 500 ppm $1,830 $8,062 $915 $4,031 $1,616 $7,290 $808 $3,645Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 re lated 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 Impac ts of Regulatory Options Based on the discussion above, we consider Regula tory 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 producti on 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 monitori ng of fugitive emissions and components using Method 21 with a 2,500 pp m repair threshold.

 Regulatory Option 2a - (10,000 ppm) - Require the implementation of a Method 21 monitoring and repair program which includes annual monitori ng of fugitive emissions and components using Method 21 with a 10,000 pp m repair threshold.

 Regulatory Option 2b - (2,500 ppm) - Require the implementation of a Method 21 monitoring and repair program which includes semiannual monito ring of fugitive emissions and components using Method 21 with a 2,500 pp m repair threshold.

 Regulatory Option 2b - (10,000 ppm) - Require the implementation of a Method 21 monitoring and repair program which includes semiannual monito ring of fugitive emissions and components using Method 21 with a 10,000 pp m repair threshold.
The number of oil and natural production well site s, gathering and boosting stations, transmission stations, and storage facilities that would be subject to the regulatory opt ions listed above were presented in Table 5-10. In 2020, it was estimated that th ere would be 16,562 uncontroll ed oil well sites, 5,518 uncontrolled gas well sites, 259 uncontrolled gathering and boosting stations, 6 uncontrolled transmission stations, and 15 uncontrolled storage f acilities subject to these options. In 2025, it was estimated that thereProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### would be 100,175 uncontrolled oil well sites, 38,393 uncontrolled gas well site s, 1,554 uncontrolled gathering and boosting stations, 36 uncontrolled tr ansmission stations, and 90 uncontrolled storage facilities subject to these options.

It was estimated that OGI monito ring and repair on an annual fr equency can achieve an overall 40 percent VOC and CH 4 

### reduction over the life span of the facility and on a semiannual frequency can achieve an overall 60 percent VOC and CH 4 

### 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 es timated by applying this 40 and 60 percent VOC
and CH 4 

### reduction to the uncontrolled base line emissions presented in Ta ble 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, th at the program frequency should be consistent across the segments in the oil and natural gas source categor y. Therefore, nationwide impacts were estimated for both of these opti ons as presented in Tables 5-30 and 5-31.
It was estimated that Method 21 monitoring a nd repair can achieve a range of VOC and CH 4 

### depending on the frequency of monitoring combined with the leak repair threshold. The percent reductions as presented in Table 5-18 range from 72 percen t (semiannual frequency with 10,000 ppm leak repair threshold) to 98 percent (annual freq uency with a 500 ppm leak repair th reshold). 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 ba seline emissions VOC and CH 4 

### 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 Pl ans (options 1a and 1b)
The operational standards for Regulatory Option 1a include both annual monitoring of fugitive emissions components using OGI and repair of fugitiv e emissions components that are found to be leaking during the survey. The annual costs fo r these surveys (as summarized in Table 5-30) are estimated to be $1,329 for oil and natural gas production well site s, $10,124 for gathering and boosting stations, $10,049 for transmission stations, and $13,634 for storage f acilities, 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 s ubmittal of an annual repo rt and the amortizationProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 re pair program was calcul ated to be 105 thousand standard cubic feet per year (Mscf/yr) for a natura l gas production well site and 25 Mscf/yr for an oil production well site. For the compresso r stations, the potential natural gas saved wa s calculated to be 815 Mscf/yr for gathering and boosting st ations, 1,292 Mscf/yr for transmi ssion 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 opera tors of these facilities do not own the natural gas
handled.
The operational standards for Regulatory Opti on 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 summari zed in Table 5-31) are estimated to be $2,230 for oil and natural gas pro duction well sites, $15,881 for gathering and boosting stations, $15,732 for transmission sta tions, and $22,902 for storage facilitie s, 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 implem entation 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. Fo r 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, a nd 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, wh ich includes an estimated annual savings of $4 million when natural gas savings are considere d. Likewise, for projected year 2025, for 100,175 oil production well sites and 38,933 natural ga s production well sites, the tota l nationwide cost was estimated to be $158.4 million, including annual savings estim ated 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 an d boosting stations. For the 1,554 new gathering and

57 Natural gas savings calculated using the CH 4 reductions and assuming a methane to natural gas volume ration of 82.9% for upstream facilities (well sites, gathering & boosting) and a me thane to natural gas volume ratio of 92.8% for downstream facilities (transmission, storage).
58 Ibid.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### boosting, 36 transmission and 90 storage facilities, th e 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 transm ission and storage facilitie s, because they do not own the natural gas that is compressed at their fa cilities. Table 5-30 summar izes the nationwide cost impacts for the projected years 2020 and 2025 for implementation of regulatory Option 1a.
Applying the cost for the semiannual OGI mon itoring 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, wh ich includes an estimated annual savings of $6 million when natural gas savings are considere d. Likewise, for projected year 2025, for 100,175 oil production well sites and 38,933 natural ga s production well sites, the tota l nationwide cost was estimated to be $270.5 million, including annual savings estim ated around $39.7 million when natural gas savings are considered. For compressor stations, which in clude 259 new gathering and boosting, 6 transmission and 15 storage facilities, the nationwide costs were estimated to be $3.3 milli on 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 fa cilities, and the nationwide costs were estimated to be $19.7 million in the projected year 2025. Annual sa vings were estimated to be $7.6 million per year for gathering and boosting stations. No annual savi ngs were estimated for transmission and storage facilities, because they do not own the natural gas that is compressed at th eir 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 l eak repair thresholds of 10,000 ppm and 2,500 ppm. Without considering gas savings, th e estimated annual costs for these surveys are estimated to range from $4,020 (annual at 10,000 pp m repair threshold) to $6,103 (semiannual at 2,500 ppm repair threshold) for oil and natural ga s production well sites and from $37,203 to $55,860 for gathering and boosting, transmission a nd storage compressor stations. This cost includes the costs for conducting the Method21 survey, activiti es planning, repair costs, resurv ey 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 implemen tation of a Method21 monito ring and repair program were calculated to range from 189 t housand standard cubic feet per y ear (Mscf/yr) to 247 Mcf/yr for aProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### natural gas production well site, from 45 to 59 Mscf /yr for an oil producti on 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 tr ansmission compressor stations and from 6,129 to 8,001 Mcf/yr for storage facility compressor stations. Howe ver, because gas handled by transmission and storage facilities is not typically owned by the operator, we do not consider th is as gas saved with respect to offsetting of costs.
Applying the cost for the annual Method 21 mon itoring and 10,000 ppm repa ir threshold to the estimated 16,562 oil production well sites and 5,518 natural gas producti on 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 pro duction 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 20 20 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 mon itoring and 2,500 ppm repair threshold to the estimated 16,562 oil production well sites and 5,518 natural gas producti on 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 pro duction 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 es timated to be $81.9 million, including $11.9 million when natural gas savings are considered. Table 5-32 summa rizes the nationwide costs for the two sub-options under Option 2a (annual Method 21 m onitoring at the 10,000 ppm and 2,500 ppm repair thresholds).
Applying the cost for the annual Method 21 mon itoring and 500 ppm repair threshold to the estimated 16,562 oil production well sites and 5,518 natural gas producti on 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 pro duction well sites, the total nationwide costProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 estim ated to be $90 million, including $12.4 million when natural gas savings are considered. Table 5-32 summa rizes 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 si tes 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 pro duction 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 20 20 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 repa ir threshold to the estimated 16,562 oil production well sites and 5,518 natural gas producti on 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 pro duction 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 es timated 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 producti on 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 pro duction well sites, the total nationwide costProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 es timated 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 and 2,500 ppm repair thresholds).Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document115Table 5-30.Nationwide Emission and Cost Analysis for Regulatory Option 1a – Annual OGI Monition and RepairFugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual Cost PerFacility($)Annual CostPer Facility($)Nationwide EmissionReductions(tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithout savingswith savingsProjected Year 2020Gas Well Site 5,518 $1,329 $908 10,019 2,785 $7.3 $5.0Oil Well Site 16,562 $1,329 $1,228 7,205 2,003 $22.0 $20.3Well Sites 22,080 NA NA 17,224 4,788 $29.3 $25.4Gathering & Boosting 259 $10,124$6,865 3,641 1,012 $2.6 $1.8Transmission 6 $10,049 $10,049 150 4 $0.1 $0.1Storage 15 $13,634 $13,634 987 27 $0.2 $0.2Compressor Stations 280 NA NA 4,777 1,043 $2.9 $2.0Projected Year 2025Gas Well Site 38,933 $1,329 $908 70,691 19,650 $51.7$35.4Oil Well Site 100,175 $1,329 $1,228 43,577 12,113 $133.1$123.0Well Sites 139,108 NA NA 114,267 31,763 $184.9 $158.4Gathering & Boosting 1,554 $10,124$6,865 21,845 6,072 $15.7$10.7Transmission 36 $10,049 $10,049 898 25 $0.4$0.4Storage 90 $13,634 $13,634 5,919 164 $1.2$1.2Compressor Stations 1,680 NANA 28,662 6,261 $17.3 $12.3Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document116Table 5-31.Nationwide Emission and Cost Analysis for Regulatory Option 1b – Semiannual OGI Monitoring and RepairFugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility($)Annual Cost PerFacility($)Nationwide EmissionReductions(tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savingsProjected Year 2020Gas Well Site 5,518 $2,230 $1,599 15,029 4,178 $12.3 $8.8Oil Well Site 16,562 $2,230 $2,079 10,807 3,004 $36.9 $34.4Well Sites 22,080 NA NA 25,835 7,182 $49.2 $43.2Gathering & Boosting 259 $15,881$10,993 5,461 1,518 $4.1 $2.8Transmission 6 $15,732 $15,732 225 6 $0.1 $0.1Storage 15 $22,902 $22,902 1,480 41 $0.3 $0.3Compressor Stations 280 NA NA 7,165 1,565 $4.6 $3.3Projected Year 2025Gas Well Site 38,933 $2,230 $1,599 106,036 29,475 $86.8 $62.2Oil Well Site 100,175 $2,230 $2,079 65,365 18,170 $223.4 $208.2Well Sites 139,108 NA NA 171,401 47,645 $310.2 $270.5Gathering & Boosting 1,554 $15,881$10,993 32,767 9,108 $24.7 $17.1Transmission 36 $15,732 $15,732 1,347 37 $0.6 $0.6Storage 90 $22,902 $22,902 8,879 246 $2.1 $2.1Compressor Stations1,680NA NA 42,993 9,391 $27.3 $19.7Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document117Table 5-32. Nationwide Emission and CostAnalysis for Regulatory Option 2a – Annual Method 21 Monitoring and RepairFugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility($)Annual Cost PerFacility($)Nationwide EmissionReductions(tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savingsProjected Year 202010,000 ppmGas Well Site 5,518 $4,020 $3,157 20,539 5,709 $22.2 $17.4Oil Well Site 16,562 $4,020 $3,813 14,769 4,106 $66.6 $63.2Well Sites 22,080 NA NA 35,308 9,815 $88.8 $80.6Gathering & Boosting 259 $37,203$30,523 7,464 2,075 $9.6 $7.9Transmission 6 $37,203 $37,203 307 8 $0.2 $0.2Storage 15 $37,203 $37,203 2,022 56 $0.6 $0.6Compressor Stations 280 NA NA 9,793 2,139 $10.4 $8.72,500 ppmGas Well Site 5,518 $6,103 $5,113 23,545 6,545 $33.7 $28.2Oil Well Site 16,562 $6,103 $5,866 16,931 4,706 $101.1 $97.1Well Sites 22,080 NA NA 40,475 11,251 $134.7 $125.4Gathering & Boosting 259 $55,860$48,203 8,556 2,378 $14.5 $12.5Transmission 6 $55,860 $55,860 352 10 $0.3 $0.3Storage 15 $55,860 $55,860 2,318 64 $0.8 $0.8Compressor Stations 280 NANA 11,226 2,452 $15.6 $13.7Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document118Fugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility($)Annual Cost PerFacility($)Nationwide EmissionReductions(tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savings500 ppmGas Well Site 5,518 $6,437 $5,406 24,547 6,823 $35.5 $29.8Oil Well Site 16,562 $6,437 $6,190 17,651 4,907 $106.6 $102.5Well Sites 22,080 NA NA 42,198 11,730 $142.1 $132.3Gathering & Boosting 259 $60,973$52,990 8,920 2,480 $15.8 $13.7Transmission 6 $60,973 $60,973 367 10 $0.4 $0.4Storage 15 $60,973 $60,973 2,417 67 $0.9 $0.9Compressor Stations 280 NANA 11,704 2,557 $17.1 $15.0Projected Year 202510,000 ppmGas Well Site 38,933 $4,020 $3,157 144,916 40,283 $156.5$122.9Oil Well Site 100,175 $4,020 $3,813 89,332 24,832 $402.7$382.0Well Sites 139,108 NA NA 234,248 65,115 $559.2 $504.9Gathering & Boosting 1,554 $37,203$30,523 44,781 12,448 $57.8$47.4Transmission 36 $37,203 $37,203 1,841 51 $1.3$1.3Storage 90 $37,203 $37,203 12,134 336 $3.3$3.3Compressor Stations 1680 NANA 58,757 12,835 $62.5 $52.12,500 ppmGas Well Site 38,933 $6,103 $5,113 163,123 46,178 $237.6$199.1Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document119Fugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility($)Annual Cost PerFacility($)Nationwide EmissionReductions(tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savingsOil Well Site 100,175 $6,103 $5,866 102,405 28,466 $611.3$587.6Well Sites 139,108 NA NA 268,528 2,147 $848.9 $786.7Gathering & Boosting 1,554 $55,860$48,203 51,335 14,270 $86.8$74.9Transmission 36 $55,860 $55,860 2,111 58 $2.0$2.0Storage 90 $55,860 $55,860 13,910 385 $5.0$5.0Compressor Stations 1680 NANA 67,355 14,713 $93.8 $81.9500 ppmGas Well Site 38,933 $6,437 $5,406 173,192 48,143 $250.6 $210.5Oil Well Site 100,175 $6,437 $6,190 106,763 29,677 $644.8 $620.1Well Sites 139,108 NA NA 279,954 77,820 $895.4 $830.5Gathering & Boosting 1,554 $60,973$52,990 53,519 14,877 $94.8 $82.3Transmission 36 $60,973 $60,973 2,200 61 $2.2 $2.2Storage 90 $60,973 $60,973 14,502 401 $5.5 $5.5Compressor Stations 1680 NA NA70,222 15,339 $102.4 $90.0Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document120Table 5-33. Nationwide Emission and CostAnalysis for Regulatory Option 2b – Semiannual Method 21 Monitoring and RepairFugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility($)Annual Cost PerFacility($)Nationwide EmissionReductions(tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savingsProjected Year 202010,000 ppmGas Well Site 5,518 $4,482 $3,725 18,034 5,013 $24.7 $20.6Oil Well Site 16,562 $4,482 $4,301 12,968 3,605 $74.2 $71.2Well Sites 22,080 NA NA 31,002 8,618 $99.0 $91.8Gathering & Boosting 259 $38,128$32,263 6,553 1,822 $9.9 $8.4Transmission 6 $38,128 $38,128 269 7 $0.2 $0.2Storage 15 $38,128 $38,128 1,776 49 $0.6 $0.6Compressor Stations 280 NA NA 8,599 1,878 $10.7 $9.22,500 ppmGas Well Site 5,518 $6,565 $5,597 23,044 6,406 $36.2 $30.9Oil Well Site 16,562 $6,565 $6,333 16,570 4,606 $108.7 $104.9Well Sites 22,080 NA NA 39,614 11,012 $145.0 $135.8Gathering & Boosting 259 $56,785$49,291 8,374 2,328 $14.7 $12.8Transmission 6 $56,785 $56,785 344 10 $0.3 $0.3Storage 15 $56,785 $56,785 2,269 63 $0.9 $0.9Compressor Stations 280 NANA 10,987 2,400 $15.9 $14.0Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document121Fugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility($)Annual Cost PerFacility($)Nationwide EmissionReductions(tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savings500 ppmGas Well Site 5,518 $6,899 $5,879 24,296 6,754 $38.1 $32.4Oil Well Site 16,562 $6,899 $6,655 17,471 4,857 $114.3 $110.2Well Sites 22,080 NA NA 41,767 11,610 $152.3 $142.7Gathering & Boosting 259 $61,898$53,996 8,829 2,454 $16.0 $14.0Transmission 6 $61,898 $61,898 363 10 $0.4 $0.4Storage 15 $61,898 $61,898 2,392 66 $0.9 $0.9Compressor Stations 280 NANA 11,584 2,530 $17.3 $15.3Projected Year 202510,000 ppmGas Well Site 38,933 $4,482 $3,725 127,243 35,370 $174.5 $145.0Oil Well Site 100,175 $4,482 $4,301 78,438 21,804 $449.0 $430.8Well Sites 139,108 NA NA 205,681 57,174 $623.5 $575.8Gathering & Boosting 1,554 $38,128 $32,263 39,320 10,930 $59.3 $50.1Transmission 36 $38,128 $38,128 1,617 45 $1.4 $1.4Storage 90 $38,128 $38,128 10,654 295 $3.4 $3.4Compressor Stations 1680 NANA 51,591 11,270 $64.1 $54.92,500 ppmGas Well Site 38,933 $6,565 $5,597 162,588 45,195 $255.6 $217.9Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document122Fugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility($)Annual Cost PerFacility($)Nationwide EmissionReductions(tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savingsOil Well Site 100,175 $6,565 $6,333 100,226 27,860 $657.6 $634.4Well Sites 139,108 NA NA 262,814 73,056 $913.2 $852.3Gathering & Boosting 1,554 $56,785$49,291 50,243 13,966 $88.2 $76.6Transmission 36 $56,785 $56,785 2,066 57 $2.0 $2.0Storage 90 $56,785 $56,785 13,614 377 $5.1 $5.1Compressor Stations 1680 NANA 65,922 14,400 $95.4 $83.8500 ppmGas Well Site 38,933 $6,899 $5,879 171,424 47,652 $268.6 $228.9Oil Well Site 100,175 $6,899 $6,655 105,673 29,375 $691.2 $666.7Well Sites 139,108 NA NA 277,098 77,026 $959.8 $895.5Gathering & Boosting 1,554 $61,898$53,996 52,973 14,725 $96.2 $83.9Transmission 36 $61,898 $61,898 2,178 60 $2.2 $2.2Storage 90 $61,898 $61,898 14,354 397 $5.6 $5.6Compressor Stations 1680 NA NA69,505 15,183 $104.0 $91.7Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### 5.5.2.3 Nationwide Impacts Excluding Low Producing Natural Gas and Oil Wells
We also evaluated an alternative nationwide imp act scenario that accounts for well sites that produce relatively little crude oil a nd/or natural gas. Under this scen ario, 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 "str ipper 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, w ith respect to any calendar year, any property with respect to which the amount dete rmined by dividing—(i) the average daily production of domestic crude oil and domestic natural gas fro m 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 da ta 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 nationwid e 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 th e well also produced oil, the number of barrels of oil produced was added to the barrel equivalents calculated for the natura l 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 comple tions 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 site s that would be covered by the NSPS fugitive emissions requirement s 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 an d 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 a lternative population of well sites for each of the regulatory options
discussed above.

59 26 U.S.C. 613A(c)(6)(E)

.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document124Table 5-34.Nationwide Emission and Cost Analysis for Regulatory Option 1a (Excluding Low-Producing Well Sites)– Annual OGI Monition and RepairFugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual Cost PerFacility ($)Annual CostPer Facility ($)Nationwide EmissionReductions (tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithout savingswith savingsProjected Year 2020Gas Well Site 3,863 $1,329 $908 7,014 1,950 $5.1 $3.5Oil Well Site 9,440 $1,329 $1,228 4,106 1,141 $12.5 $11.6Well Sites 13,303 NA NA 11,120 3,091 $17.7 $15.1Projected Year 2025Gas Well Site 27,253 $1,329 $908 49,483 13,755 $36.2$24.8Oil Well Site 57,100 $1,329 $1,228 24,839 6,905 $75.9$70.1Well Sites 84,353 NA NA 74,322 20,660 $112.1 $94.9Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document125Table 5-35.Nationwide Emission and Cost Analysis for Regulatory Option 1b (Excluding Low-Producing Well Sites)– Semiannual OGI Monition and RepairFugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual Cost PerFacility ($)Annual Cost PerFacility ($)Nationwide EmissionReductions (tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithout savingswith savingsProjected Year 2020Gas Well Site 3,862 $2,230 $1,599 10,518 2,924 $8.6 $6.2Oil Well Site 9,440 $2,230 $2,079 6,160 1,712 $21.0 $19.6Well Sites 13,302 NA NA 16,678 4,636 $29.7 $25.8Projected Year 2025Gas Well Site 27,253 $2,230 $1,599 74,225 20,633 $60.8$43.6Oil Well Site 57,100 $2,230 $2,079 37,258 10,357 $127.3$118.7Well Sites 84,353 NA NA 111,483 30,989 $188.1 $162.3Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document126Table 5-36. Nationwide Emission and CostAnalysis for Regulatory Option 2a(Excluding Low-Producing Well Sites)– Annual Method 21 Monitoring and RepairFugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility ($)Annual Cost PerFacility ($)Nationwide EmissionReductions (tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savingsProjected Year 202010,000 ppmGas Well Site 3,863 $4,020 $3,157 14,379 3,997 $15.5 $12.2Oil Well Site 9,440 $4,020 $3,813 8,418 2,340 $37.9 $36.0Well Sites 13,303 NA NA 22,797 6,337 $53.5 $48.22,500 ppmGas Well Site 3,863 $6,103 $5,113 16,483 1,212 $23.6 $19.8Oil Well Site 9,440 $6,103 $5,866 9,650 236 $57.6 $55.4Well Sites 13,303 NA NA 26,133 1,449 $81.2 $75.1500 ppmGas Well Site 3,863 $6,437 $5,406 17,184 4,777 $24.9 $20.9Oil Well Site 9,440 $6,437 $6,190 10,061 2,797 $60.8 $58.4Well Sites 13,303 NA NA 27,245 7,573 $85.6 $79.3Projected Year 202510,000 ppmGas Well Site 27,253 $4,020 $3,157 101,441 28,198 $109.6$86.0Oil Well Site 57,100 $4,020 $3,813 50,920 14,154 $229.5$217.7Well Sites 84,353 NA NA 152,360 42,352 $339.1 $303.82,500 ppmGas Well Site 27,253 $6,103 $5,113 116,285 1,229 $166.3$139.4Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document127Fugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility ($)Annual Cost PerFacility ($)Nationwide EmissionReductions (tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savingsOil Well Site 57,100 $6,103 $5,866 58,371 236 $348.5$334.9Well Sites 84,353 NA NA 174,657 1,466 $514.8 $474.3500 ppmGas Well Site 27,253 $6,437 $5,406 121,234 33,700 $175.4 $147.3Oil Well Site 57,100 $6,437 $6,190 60,855 16,916 $367.6 $353.4Well Sites 84,353 NA NA 182,089 50,616 $543.0 $500.8Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document128Table 5-3737. Nationwide Emission and Cost Analysis for Regulatory Option 2b (ExcludingLow-Producing Well Sites)– Semiannual Method 21 Monitoring and RepairFugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility ($)Annual Cost PerFacility ($)Nationwide EmissionReductions (tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savingsProjected Year 202010,000 ppmGas Well Site 3,863 $4,482 $3,725 12,622 3,509 $17.3 $14.4Oil Well Site 9,440 $4,482 $4,301 7,392 2,055 $42.3 $40.6Well Sites 13,302 NA NA 20,014 5,563 $59.6 $55.02,500 ppmGas Well Site 3,863 $6,565 $5,597 16,128 1,186 $25.4 $21.6Oil Well Site 9,440 $6,565 $6,333 9,445 231 $62.0 $59.8Well Sites 13,302 NA NA 25,573 1,418 $87.3 $81.4500 ppmGas Well Site 3,863 $6,899 $5,879 17,009 4,728 $26.7 $22.7Oil Well Site 9,440 $6,899 $6,655 9,958 2,768 $65.1 $62.8Well Sites 13,303 NA NA 26,967 7,496 $91.8 $85.5Projected Year 202510,000 ppmGas Well Site 27,253 $4,482 $3,725 89,070 24,759 $122.2$101.5Oil Well Site 57,100 $4,482 $4,301 44,710 12,428 $255.9$245.6Well Sites 84,353 NA NA 133,780 37,187 $378.1 $347.12,500 ppmProposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document129Fugitive EmissionComponent LocationNumber ofSourcesSubject toNSPSAnnual CostPer Facility ($)Annual Cost PerFacility ($)Nationwide EmissionReductions (tpy)Total Nationwide Costs(million $/year)without savingswith savingsCH4VOCwithoutsavingswith savingsGas Well Site 27,253 $6,565 $5,597 113,811 1,203 $178.9$152.5Oil Well Site 57,100 $6,565 $6,333 57,129 231 $374.9$361.6Well Sites 84,353 NA NA 170,941 1,435 $553.8 $514.1500 ppmGas Well Site 27,253 $6,899 $5,879 119,997 33,356 $188.0 $160.2Oil Well Site 57,100 $6,899 $6,655 60,234 16,744 $394.0 $380.0Well Sites 84,353 NA NA 180,231 50,100 $582.0 $540.2.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

130 

## 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. Pneu matic controllers are used throughout the oil and natura l 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 th eir function and associated emissions. Standards are already in place for pneumatic controllers in the pr oduction and processing segment; therefore they are not discussed here. Options availabl e 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 fo r pneumatic controllers.


### 6.1 Process Description

6.1.1 Pneumatic Controllers For the purpose of this document, a pneumatic c ontroller 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 ga s and/or a supplemental supply of pow er gas. In the vast majority of applications, the natural gas industr y uses pneumatic controllers that make use of readily available highpressure natural gas to provide th e required energy and control signals . In the transmission and storage segment, an estimated 84,000 pneumatic controllers actuate is olation valves and regulate gas flow and pressure at compressor stations, pipelines, and storage facilities. 60



### Pneumatic controllers are automate d instruments used for maintaining a process condition such as liquid level, pressure, pressure diffe rential, and temperature. In many s ituations 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 thes e “gas-driven” pneumatic controllers, natural gas may be released with every valve movement and/or contin uously from the valve co ntrol 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. Sim ilar designs will have similar stea dy-state rates when operated under
similar conditions. There are three ba sic designs: (1) continuous bleed de vices are used to modulate flow,

60 U.S. EPA. Lessons Learned: Options for Reducing Methane Em issions From Pneumatic Devices in the Natural Gas Industry. OAR: Natural Gas Star. Washington, DC. February 2004.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

131 

### 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 pipe line 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 r ecognized that “closed loop” systems are applicable only in instances with very low pressure 61 

### 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 additi on to the controller’s bleed stream. Since actuation emissions serve the controller’s functional pur pose 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 incl ude 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 controller s 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 controll ers under the 2012
NSPS.
In addition, not all pneumatic contro llers are gas driven. At sites w ith electrical service sufficient to power an instrument air compressor, mechanical or solar-powered, electr ically powered pneumatic devices can be used. These “non-gas driven” pneumatic controllers can be mechanically operated or use sources of power other than pressu rized 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 relate d to generation of the electrical power required to drive the instrume nt air compressor system. Instrument air systems are feasible only at oil and natural gas locations where the devices can be driven by comp ressed 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

132 

### processing plants are the only faciliti es in the oil and natural gas source category likely to have electrical service sufficient to power an inst rument 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 pneuma tic controllers in the transmission and storage segment and the potential options available to redu ce the emissions, numerous studies and sources of information were consulted. Table 6-1 presents these st udies and sources of information with an indication of the type of relevant inform ation contained in each resource.
Table 6-1. Major Studies and Sources of Informat ion 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 Document a EPA 2013 Nationwide X

Inventory of GHG Emissions and Sinks: 1990-2012 b EPA 2014 Nationwide/ Regional X

CH 4 Emissions from the Natural Gas Industry c GRI/EPA 1996 Nationwide X

CH 4 Emissions from the Petroleum Industry (draft) d EPA 1996 Nationwide X

CH 4 Emissions from the Petroleum Industry e EPA 1999 Nationwide X

Oil and Gas Emission Inventories for Western States f Western Regional Air Partnership 2005 Regional X

Natural Gas STAR Program g EPA 2000- 2010 X X

Measurements of CH 4 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 Columbia i 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

133 Air Pollutant Emissions from the Development, Production, and Processing of Marcellus Shale Natural Gas j Carnegie Mellon University 2014 Regional (Marcellus Shale) X

Economic Analysis of CH 4 Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries k ICF International 2014 Nationwide X X

a. U.S. EPA. GHG Emissions Reporting From the Petroleum a nd Natural Gas Industry: Backgr ound TSD. Climate Change Division. Washington, DC. November 2010. b U.S. EPA. Methodology for Estimating CH 4 and CO 2 Emissions from Natural Gas System s. GHG Inventory: Emission and Sinks 1990-2008. Washington, DC. and U.S EPA. Methodology for Estimating CH 4 and CO 2 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 Interna tional 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: Ac tivity Factors. Prepared for the GRI and EPA. EPA-600/R-96- 080e. June 1996, and Radian International LLC. Methane Emi ssions 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 Corpora tion (CETAC)-WEST. Fuel Gas Best Management Practices: Efficient Use of Fuel Gas in Pneumatic Instruments. Prepar ed for the Canadian Association of Petroleum Producers. May 2008. 

### 6.2.2 Representative Pneumatic Device Emissions Continuous bleed pneumatic controlle rs can be classified into tw o types based on their emissions rates: (1) high-bleed controllers and (2) low-bleed c ontrollers. A controller is considered to be highbleed when the continuous bleed emissions are in exce ss 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 informati on in the appendices of the Natural Gas STAR Lessons Learned document on pneumatic devi ces, Subpart W of the GHG Reporting rule 64 

### , the Inventory
of GHG Emissions and Sinks , new studies, as well as pneumatic c ontroller vendor information obtained

63 The classification of high-bleed and low-bleed devices origin ated 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. Th e data obtained from vendors included emission rates, costs, and any other pertinent information fo r each pneumatic device mode l (or model family). All pneumatic devices that a vendor offere d were itemized and inquiries were made into the specifications of each device and whether it was applicable to oil a nd natural gas operations. High- bleed and low-bleed devices were differentiated using th e 6 scfh threshold. Since publicati on of the white paper, additional data have become available on emissions from pneu matic controllers, including reporting year 2013 data from GHGRP, and new measurement data from S ubramanian et al. 2015, and Allen et al. 2014. GHGRP reported methane emissions for 2013 are 190,008 tons CO 2 

### e in transmission, and 111,555 tons CO 2 

### e 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 averag e 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 lo w-bleed device available currently on the market emits lower than the maximum rate allocated for the device type. Specif ically, 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 sufficien t information about the prevalence of each model type in the population of devi ces; 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 Ga s Industry (Subpart W).
The basic approach used for this analysis of em issions from pneumatic controllers was to first approximate the natural gas emissions from the averag e pneumatic controller type in the transmission and storage segment then estimate CH 4 

### and VOC using a representative gas composition. 67



### The specific ratios from the representa tive gas composition were 0.908 lbs of CH 4 

### per pound of natural gas and 0.0277 lbs VOC per pound CH 4 

### . 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

135 

### Table 6-2. Average Bleed Emission Estimates per Pneumatic Controller in the Natural Gas Transmission and Storage Segment a, b
High-Bleed (tpy) Low-Bleed (tpy) CH 4 VOC CH 4 VOC
3.013 0.083 0.227 0.00628
a. The conversion factor used in this analysis is 1,000 cubic feet (Mcf) of CH 4 is equal to 0.0208 tons CH 4 . 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 Controll ers Installed Annually The number of pneumatic contro llers 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 prio r 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 inst alled 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 averag e 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 estimat ed in absence of regulation was undeterminable due to the magnitude of new sources estimated and the lack of sufficient data that co uld 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 pn eumatics 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 in termittent and blee d controllers was based on raw data from the GRI study, where 32 percen t of the pneumatic controllers are bleed devicesProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

136 

### 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 numb er of high-bleed and low-bleed devices was not estimated because this analysis assume s it is not possible to predict or ensure where low
bleeds will be used in the future. Table 6-3 summari zes 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 Year a, b
Intermittent Bleed-Devices Total 558 262 820 a. National averages of population counts from the Inventor y 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 contro llers 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 pneuma tic devices for new sour ces in a typical year are summarized in Table 6-4. This analysis assume d for the nationwide emission estimate that all bleeddevices have the high-bleed emission rates estima ted in Table W-3 of the GHG Reporting Rule, Subpart W since it cannot be predicted which sources would inst all a low bleed versus a high bleed controller.

Table 6-4. Nationwide Baseline Emissions from Rep resentative Pneumatic Controller Installed in a Typical Year in Natural Gas Transmission and Storage Segment a, 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) CH 4 VOC CH 4 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 CH 4 was used. 

### 6.4 Control Techniques Several options to reduce emissions have been de veloped over the years to reduce emissions from pneumatic controllers. Table 6-5 provides a summa ry of these options for reducing emissions from pneumatic controllers including: inst rument air, non-gas driven controls , and enhanced maintenance. The

68 See footnote 51.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

137 

### use of instrument air systems, as discussed in the 2012 NSPS TSD 69 

### , requires a constant source of electric power. Because electric power is not necessarily availabl e at all transmission and storage affected facilities, the use of instrument air system s would not be practically feasible as a control for emissions from pneumatic controllers in this indu stry 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 opti on would be considered to be too variable and costly as a viable option for control pneumatic c ontroller emissions. Based on these concerns, further analyses of these options were not conducted
Given the various applicability, co st of emissions reductions and cost issues with the control options, the replacement of a high-bl eed with a low-bleed device is the most likely scenario for reducing emissions from pneumatic controllers. This conclu sion is consistent with and supported by requirements of States such as Colorado and Wyoming that require the use of low-bleed cont rollers in place of highbleed controllers. Therefore, low-bl eed controllers are further descri bed in the following section, along with estimates of the impacts of their application for a representative devi ce 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 a pplication 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.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document138Table 6-5. Alternative Control Options for Pneumatic ControllersOptionDescriptionApplicability/EffectivenessEstimated Cost RangeInstall Low BleedDevice in Place ofHigh Bleed DeviceLow-bleed devices provide the same functionalcontrol as a high-bleed device, while emitting lesscontinuous bleed emissions.Applicability may depend on the functionof instrumentation for an individual deviceon whether the device is a level, pressure,or temperature controller.Low-bleed devicesare, on average,around $165 morethan high bleedversions.Convert toInstrument AiraCompressed air may be substituted for natural gas inpneumatic systems without altering any of the parts ofthe pneumatic control. In this type of system,atmospheric air is compressed, stored in a tank, filteredand then dried for instrument use. For utility purposessuch as small pneumatic pumps, gas compressor motorstarters, pneumatic tools and sand blasting, air wouldnot need to be dried. Instrument air conversion requiresadditional equipment to properly compress and controlthe pressured air. This equipment includes acompressor, power source, air dehydrator and airstorage vessel.Replacing natural gas with instrument air inpneumatic controls eliminates VOC emissionsfrom bleeding pneumatics. These systems canachieve 100 percent reduction in emissions. Itis most effective at facilities where there are ahigh concentration of pneumatic controlvalves and an operator present. Since thesystems are powered by electric compressors,they require a constant source of electricalpower or a back- up natural gas pneumaticdevice.A complete costanalysis is provided inSection 6.4.2.System costs aredependent on size ofcompressor, powersupply needs, labor andother equipment.Mechanical andSolar PoweredSystems in place ofBleed DevicebMechanical controls operate using a simple designcomprised of levers, hand wheels, springs and flowchannels. The most common mechanical control deviceis the liquid-level float to the drain valve position withmechanical linkages. Electricity or small electricalmotors (including solar powered) have been used tooperate valves. Solar control systems are driven by solarpower cells that actuate mechanical devices usingelectric power. As such, solar cells require some type ofback-up power or storage to ensure reliability.Application of mechanical controls islimited because the control must be locatedin close proximity to the processmeasurement. Mechanical systems are alsoincapable of handling larger flowfluctuations. Electric powered valves areonly reliable with a constant supply ofelectricity. Overall, these options areapplicable in niche areas but can achieve100 percent reduction in emissions whereapplicable.Depending on supply ofpower, costs can rangefrom below $1,000 to$10,000 for entiresystems.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document139OptionDescriptionApplicability/EffectivenessEstimated Cost RangeEnhancedMaintenancecInstrumentation in poor condition typically bleeds 5 to10 scf per hour more than representative conditions dueto worn seals, gaskets, diaphragms; nozzle corrosion orwear, or lose control tube fittings. This may not impactthe operations but does increase emissions.Enhanced maintenance to repair andmaintain pneumatic devices periodically canreduce emissions. Proper methods ofmaintaining a device are highly variable andcould incur significant costs.Variable based onlabor, time, and fuelrequired to travel tomany remote locations.a. U.S. EPA. Lessons Learned: Convert Gas Pneumatic Controls toInstrument Air. OAR: Natural Gas Star. Washington, DC. February2004.b. U.S. EPA. PRO Fact Sheet No. 301. Convert Pneumatics to Mechanical Controls. OAR: Natural Gas Star. Washington, DC. September 2004.c.CETAC-WEST. Fuel Gas Best Management Practices: Efficient Use ofFuel Gas in Pneumatic Instruments. Prepared for the CanadianAssociation of PetroleumProducers. May 2008.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

140 

### 6.4.1 Low-Bleed Controller Emi ssion 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 emissi ons per controller is estimated to be approximately 2.79 tons of
CH 4 

### and 0.077 tons of VOC. As noted in section 6.2, a lo w-bleed controller can emit up to 6 scfh, which is higher than the expected emissions from the ty pical low-bleed device cu rrently available on the
market.

Table 6-6. Estimated Annual Bleed Emission Re ductions 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-Bleed a (tpy)
CH 4 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 wh ich replacing and retrofitting are not feasible, such as instances where a minimal response time is needed, cases where larg e valves require a high bleed rate to actuate, or a safety isolation valve is involved. Based on criter ia provided by the Natural Gas STAR Program, it is assumed about 80 percent of high-bl eed devices can be replaced with low-bleed devices throughout the transmission and storage segment. 70 

### This corresponds to 210 new hi gh-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 instru mentation for an individual device such as whether the device is a level, pressure, or temperat ure 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 potentia lly result in damage to equipment and/or become a safety issue. An example of this is on a compressor where pneumatic devices ma y monitor the suction and discharge pressure and actuate a re-cycle when one or the ot her is out of the specified target range. Other scenarios for fast and precise control include transient (non-steady) situati ons where a gas flow rate may fluctuate widely or

70 See footnote 49.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### unpredictably. This situation requires a responsive high- bleed device to ensure th at the gas flow can be controlled in all situations. Temperat ure and level controllers are typica lly present in control situations that are not prone to fluctuate as widely or where the fluctuat ion can be readily and safely accommodated by the equipment. Therefore, such pro cesses can accommodate control from a low-bleed device, which is slower-a cting and less precise.
6.4.3 Cost Impacts
As described in Section 6.2.2, cost s were based on the vendor rese arch as a result of updating and expanding upon the information given in the appendi ces 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 hi gh-bleed was annualized for a 15-year period using a 7 percent in terest rate. This equated to an annu alized cost of around $25 per low-bleed
controller. Table 6-7. Cost Projections for Repres entative 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 additiona l gas captured to the sales line exists, these savings were not estimated for the transmission and st orage segment because it is assumed the owner of the pneumatic controller generally is not the owner of the natural gas. The co st 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 prorat ed costs among the pollutants that a given technology reduced (i.e., CH4 and VOC). This proration was based on estimate s of the percentage reduc tion 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### Table 6-8. Cost-of Control for Low-Bleed Pneumati c Controllers versus High Bleed Pneumatics for the Transmission and Storage Segment (2012)

Method Incremental Capital Cost Per Unit a ($) Total Annual Cost Per Unit b ($/year) Emissions Reductions (tpy) Cost of Control ($/ton)
CH 4 VOC CH 4 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 intere st rate over a 15-year equipment lifetime. 

### 6.4.4 Secondary Impacts Low-bleed pneumatic controllers are a replacemen t 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 ge nerated, 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 c ontroller is defined as a single natural gas pneumatic controller. Therefore, pneumatic controlle rs 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 em issions limit equal to 6 scfh.
6.5.1 Evaluation of Regul atory Options By establishing an emission limit of 0 scfh, facilitie s would most likely need to install instrument air systems to meet the threshold limit. Because facili ties located in the transmission and storage segment might not always have sufficient elec trical service to install an instru ment air systems, this option would not be practically feasible in all situations. In addition, th e cost of supplying elec tric power (which is highly variable) would need to be co nsidered, which would likely render th e cost of this control option to be unreasonable. Therefore Regulatory option 1 was reje cted for facilities in the transmission and storage segment.
Regulatory Option 2 would establ ish an emission limit equal to the maximum emissions allowed for a low-bleed device in the transmission and storag e segment. This would most likely be met by the use of low-bleed controllers in place of a high-bleed controller, but allows fl exibility in the chosen method ofProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### meeting the requirement. In the key instances related to pressure control that w ould disallow the use of a low-bleed device, specific monitoring and recordkeepi ng 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 natu ral gas processing plants.
6.5.2 Nationwide Impacts of Regulatory Options Table 6-9 summarize the costs impacts of the se lected 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 nationw ide capital cost of $47,670 and annual costs of $5,250 for projected year 2020. For the projected year 2025, we estimate the numbe r of new affected facilities for the years 2020 through 2025. As mentioned above, because the natura l 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 Reducti on Impacts for Selected Regulatory Option

Number of

Affected Facilities a Capital Cost Per Controller b ($) Annual Costs ($/year) Nationwide Emission Reductions (tpy) Total Nationwide Costs ($/year)

CH 4 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 blee d 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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## 7.0 PNEUMATIC PUMPS The natural gas industry uses a variety of pneuma tic gas powered pumps wh ere there is no reliable electrical power to “control proce ssing problems and protect equipment.” 73 

### Pneumatic pumps are “small positive displacement, reciprocating units used thr oughout the oil and natural gas production sector to inject precise amounts of chemicals into process st reams [or for freeze protection glycol circulation].” 74 

### Most chemical injection pumps (CIPs) fall into two ma in types: diaphragm, generally for heat tracing or plunger/piston, generally for chemical and methanol in jection. This chapter describes pneumatic pumps including their function a nd associated emissions. Options availabl e to reduce emissions from pneumatic pumps are presented, along with costs, emission reduc tions, and secondary impacts. Finally, this chapter discusses considerations in developing re gulatory 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, wher eas in processing, the supply gas ma y be compressed air. In these gasdriven pneumatic pumps, characteristics that affect CH 4 

### emissions include “the frequency of operation, the size of the unit, the supply gas pressure, and the inlet CH 4 

### composition.” 76



### Pneumatic pumps are generally used for one of three purposes: glyc ol 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 th e 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-t ransfer fluids in tubing covered with insulation to prevent freezing in pipelines, vessels and tanks. CIPs , i.e. piston/plunger pumps or sma ll diaphragm pumps, inject small desired amounts of chemicals such as methanol to pr event 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 Natura l 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### energy to the driver side of the pump, which operates a piston or flexible diaphrag m to draw fluid into the pump. The motive side of the pump de livers the energy to the fluid being moved in order to discharge the fluid from the pump. The natural gas l eaving the exhaust port of the pump is either directly discharged into the atmosphere or is recovered and us ed 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 reci procating stroke includ es two movements, refe rred to as an upward motion or suction stroke, and a downward motion or pow er stroke. During the suc tion 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 h ead of the liquid being pumped. Simultaneously, the discharge check valve remains close d, thus allowing the chemical to re main in the fluid chamber. During the power stroke, the plunger assembly is forced downwards, immediately shu tting off the suction check valve. Simultaneously, the chemical is displaced, fo rcing 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 fiel d are biocides, demulsifiers, clarifiers, corrosion inhibitors, scale inhibitors, hydrat e inhibitors, paraffin dewaxers, su rfactants, oxygen scavengers, and H 2 

### S 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 co ntaining the chemical being injected. 80



### Diaphragm pumps work by flexi ng 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-dr iven. 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 system s have other energy impacts, with associated

78 See footnote 48.
79 Ibid.
80 Ibid.
81 GlobalSpec. Diaphr agm Pumps Information. Available at http://www.globalspec. com/learnmore/flow_transfer_ control/pumps/diaphragm_pumps

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### secondary impacts related to genera tion of the electrical power requir ed to drive the instrument air compressor system. Instrument air systems are feasib le only at oil and natural gas locations where the devices can be driven by compresse d instrument air systems and have electrical service sufficient and reliable enough to power an air cont rol system. This analysis assumed th at 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, a nd that most existing gas processing plants use instrument ai r 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 st udies were consulted. Table 7-1 lis ts these references with an indication of the type of relevant information contained in each study.
Table 7-1. Major Studies Reviewed for Consid eration 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

CH 4 Emissions from the Natural Gas Industry GRI/EPA 1996 Nationwide X

CH 4 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 CH 4 

### emission estimates for pneumatic pumps ar e 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 provi ded in the following sections.

82 Radian International LLC. Methane Emissions from the Natura l 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 informati on in the appendices of the Natural Gas STAR Lessons Learned document on pneumatic pumps 83,84 

### , Subpart W of the GHG Reporting rule 85 

### , U.S. GHG
Natural Gas and Petroleum Inventories 86 

### , and U.S. EPA GRI Report 87 

### . 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 da ta is the U.S. EPA GHG Inventory. Since publication of the white paper, additional da ta have become available on emissions from pumps, including GHGRP 2013 reporting year data. In 2013, reported methane em issions from chemical injection pumps in the production segment were 3,046,012 tons of CO 2 

### e.
The basic approach used for this an alysis was to first approximate CH 4 

### 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 CH 4 

### per pound CH 4 

### in the production and processing segments, and 0.0277 lbs VOC per pound CH 4 

### 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. Pr o Fact Sheet No. 301. Convert Pneumatics to Mechanical Cont rols. 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/ghgemiss ions/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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 CH 4 CH 4 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 Natura l 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 y ear 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 produc tion (which includes na tural gas gathering and boosting), natural gas processing, and natural gas tr ansmission and storage. The methodologies that
determined the estimated count of new CIPs in stalled in a typical ye ar 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 ty pical year was estimated by review ing the annual count of CIPs fromProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### the year 1990 to 2012 reported in the GHG Inventory for the natural gas and oil pr oduction 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 insta lled between two years were not c onsistent. The average change for the entire period was estimated to be 877 for natural ga s facilities and -161 for o il facilities. Additionally, the average change over the last 10 years was estimated to be 1480 for na tural 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 curr ent growth of CIPs. Theref ore, for this analysis,
the counts of new CIPs that would be affected so urces 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, th e replacement count for CIPs was estimated to be 340 diaphragm pumps and 340 piston pumps.
The GHG Inventory 89 

### 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 esti mated count of new pumps installed per year.

89 See footnote 80
90 See footnote 81.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 Rep resentative Chemical Injection Pumps Installed in a Typical Year for the Oil and Natural Gas Industry

Segment/Pump Type Number of New Pumps a Emission Factor (tpy) b Nationwide Emissions (tpy) CH 4 VOC CH 4 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 CH 4 

### during normal operations. Depe nding 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 re ducing emissions from gas-driven chemical pumps including: instrument air, solar, electricity, or routing emissions to a gas capture system or flare.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 un it (VRU), or sent to a combustion
device. Identified emission control options for gas-driven pumps are described in the following section.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document152Table 7-5. Alternative ControlOptions for Gas-Driven PumpsOptionDescriptionApplicability/EffectivenessEstimated Cost RangeConvert to SolarPumpsSolar power cells can generateelectricity to power the pump. Solarcells can utilize a back-up powersystem to ensure reliability.Solar powered pumps are only reliable inareas where the sun can power the pumpreliably. These devices, when applicablecan result in 100 percent reduction inemissions where applicable.Capital costs for converting tosolar pumps is approximately$2,300 per deviceCovert to ElectricPumpsElectric pumps can be used where areliable source of electricity isavailable at the facility.Electric powered pumps are only reliablewith a constant supply of electricity.Overall, this option is applicable in nicheareas but can achieve 100 percentreduction in emissions where applicable.Capital costs range between$1,807 to $5,352 plus electricitycosts and an average annualmaintenance cost of $263 perdevice.Convert to InstrumentAir9186Instrument air systems can be used byreplacing compressed air for the gas inpumps. These systems include acompressor, electrical power source,air dehydrator (depending on the typeof pump), and volume tank.Instrument air systems reduce emissionsby 100 percent by replacing natural gaswith instrument air. This technologyoffers economies of scale, where it ismore economical at facilities with morepneumatic pumps. The system requires areliable source of electrical power.A complete cost analysis isprovided in Section 7.3.3 Systemcosts are dependent on size ofcompressor, power supply needs,labor and other equipment.Route natural gas to anExisting ControlDeviceRouting natural gas from a gas-drivenpump entails piping to a control deviceinlet stream.Routing natural gas pumps to acombustion device reduces VOC and CH4emissions by 95 percent. Routing naturalgas to a control device is an option whena control device with available capacity ispresent on site.Capital costs will varydepending on the distance ofpipeline necessary, but areapproximately $1,500 perdevice.Route natural gas toNewly InstalledControl DeviceRouting natural gas from a gas-drivenpump to a control device requiresinstallation of a control device andpiping between the pump and thecontrol device.Routing natural gas-driven pumps to acombustion control device typicallyreduces VOC and CH4emissions by 95percent. Routing natural gas to a controldevice is an option when utilities (i.e.,electricity, water) needed to run thedevice are readily available.Capital costs will beapproximately $48,500 withannual costs around $104,000.Route Natural Gas toExisting Gas CaptureSystemRouting natural gas from a gas-drivenpump entails piping to a VRU.Routing natural gas-driven pumps to aVRU reduces VOC and CH4emissionsthrough gas capture where emissionreduction efficiencies are typically 95percent. Routing natural gas to a VRU isCapital costs will varydepending on the distance ofpipeline necessary, but areestimated to be approximately$1,500 per device.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document153OptionDescriptionApplicability/EffectivenessEstimated Cost Rangeapplicable when an existing VRU withavailable capacity is present on site.Route Natural Gas toNewly Installed GasCapture SystemRouting natural gas from a gas-drivenpump to a gas capture system requiresthe installation of a gas capture systemsuch as a VRU and piping between thepump and the capture system. Theremust also be an onsite use for thecaptured gas such as a combustionengine; otherwise, a control devicewould be required.Installing a VRU and sending natural gasfrom pumps results in emission reductionsof approximately 95percent. This optionis most effective at facilities with a largenumber of pumps, and other emissionsources that can also be sent to the VRU.Capital costs will beapproximately $36,000 withannual costs around $7,500.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### 7.3.1 Solar Pumps

7. 3.1.1 Emissions Reduction Potential Solar pumps provide the same func tionality as gas-driven pumps, and can be utilized at remote
sites where a reliable source of elec tricity is not available. Solar-char ged DC pumps can handle a range of throughputs up to 100 gallons per da y with maximum injection pre ssure around 3,000 pounds per square inch gage (psig) and have zero natural gas emissions. Replacing a natural gas-dr iven pump with a solar pump can result in 100 percent re duction in methane and VOC emissions. We estimate converting natural gas-driven chemical pumps to solar-powered pumps can reduce CH 4 

### 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. Like wise, for the transmission and storage segment, we estimate that replacement of a natural gas-driven pump with a solar-powered pump will reduce CH 4 

### 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 t ons per year for a piston pump.

7.3.1.2 Effectiveness Replacing a natural gas-driven pump with a sola r 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 requir ed. Solar-powered pumps are typica lly low volume pumps that inject
methanol or corrosion inhibitors into a well with t ypical 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 replacemen t 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. Ba sed 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 Na tural Gas-Driven Chemical Pumps. Available at http://www.epa.gov/gasstar/documents/convertgasdrivenchemicalpumpstoinstrumentair.pdf

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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 co st, 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 estim ate 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 save d 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 ha ve zero natural gas emissions, as summarized in Table 7-6, and converting gas-driven ch emical pumps to an electric pump can reduce CH 4 

### emissions by an estimated 3.46 tons pe r year per diaphragm pump and 0.38 tons per year per piston pump. Based on the gas composition for natural gas in the produc tion 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. Likewi se, for the transmission and storage segment, we estimate that replacement of a pneumatic pump with an electric pump will reduce CH 4 

### 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 pu mp 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 resu lt 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 la rge dehydration facilities th at have access to reliable

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### 7.3.2.3 Cost Impacts The primary costs associated with converting natu ral 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 th e 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 elect ric 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 dia phragm pumps and $87 per ye ar per piston pump.

7.3.2.4 Secondary Impacts
The secondary impacts from electric pumps ar e 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 natura l gas and compressed air, wi thout altering any of the parts of the pump, but instrument air eliminates the emi ssions of natural gas. All f acilities that have access to a reliable source electricity can install an inst rument air system. A desc ription of each of the components as described in the Natural Gas STAR document, “PRO Fact Shee t: Convert Gas Pneumatic
Controls to Instrument Air”: 95



###  Compressors used for instrument ai r delivery are available in various types and sizes, from rotary screw (centrifugal) compressors to positive displ acement (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.
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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 inst rument air control system is th e 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 e ither 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 e ffective for remote locat ions, which reduce both
CH 4 

### emissions and energy consumption. Small natu ral gas powered fuel cells are also being developed.

 Dehydrators, or air dryers, are an integral part of the instrume nt 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 w ithdrawal of compressed air for a short time, without affecting the process control functions.

7.3.3.2 Emission Reduction Poten tial and Effectiveness
Instrument air eliminates all emissions from natura l gas-driven pumps, but can only be utilized in
locations with sufficient and reliab le electrical power. Furthermore, instrument air systems are more
economical and therefore more common at facilities wi th 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 chem ical pumps to instrument air, CH 4 

### emissions can be reduced by an estimated 3.46 tons per year per diaphragm pump and 0.38 tons per ye ar 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 ye ar per diaphragm pump and 0.11 tons per year for a piston pump. Likewise, fo r 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### that replacement of a pneumatic pump conve rted to instrument air will reduce CH 4 

### emissions can be reduced by an estimated 3.46 tons per year per dia phragm pump and 0.38 tons pe r year per piston pump and VOC emissions by 0.1 tons per year per diaphrag m 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 lo cation. The compressor size is equivale nt to the volume of natural gas used by the control loops after adjusting for gas losse s during drying, plus any uti lity air necessary at the facility. This volume can either be ca lculated via a meter or utilizing a ru le of thumb of one cubic foot per minute (cfm) of instrume nt air per control loop. 97



### For natural gas processing, the cost of emissions reduction of the th ree representative instrument air system sizes was evaluated based on the emissions mitigated from the numb er of control loops the system can provide and not on a per device basis. Th is approach was chosen because we assume new processing plants will need to provid e instrumentation of multiple contro l loops and size th e instrument air system accordingly. As was discussed in the 2011 NSPS TSD, we assume that existing processing plants have an instrument air system in pl ace, including backup systems, and th at the cost of adding additional air load to the system would be confined to the increm ental cost of upgrading or replacing the compressor and connecting the natural gas-driven pumps to the syst em. Therefore, for this analysis, the cost being attributed to the replacement of na tural gas-driven pumps with air-dri ven pumps includes the annualized cost of replacing or adding a compre ssor and installation of the associated piping to connect the pumps to the existing system, and the associated energy cost s 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 char acterize the number and types of gas-driven pumps at natural gas processing plants, we developed several model plant s cenarios that would likely cover a reasonable range of the numbers and types of pumps that might be f ound 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 be tween natural gas-driven diaphragm and piston pumps, we also evaluated, within each model plant, three distributi on scenarios for the pumps (i.e. 50 percent diaphragm and 50 percent piston, 25 percent diaphragm and 75 percent piston, a nd 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 an d 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 cap acity of the system. We determined that there were basically three sizes (small, medium and larg e) 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 us ed in our analysis were drawn from the costing analysis conducted for the 2011 NSPS proposal for inst rument air systems for pneumatic controllers (See Section 5 of the 2011 TSD). We estimated costs, includ ing operating costs, at three size levels; small, medium and large. Table 7-7 summarizes the cost re placement 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 syst ems are indirect, variab le and dependent on the electrical supply used to power the compressor. No other sec ondary impacts are expected.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document160Table 7-6. Model Plant Characterization for Replacing Gas-Driven Pumps with Instrument Air SystemModelPlant SizeAnnualCompressorCostaPumpDistributionScenariobTotalNumberof PumpsNumber ofDiaphragmPumpsNumberof PistonPumpsTotalAdditionalAirCapacityRequired(scf/hour)Gas Savedc(Mcf)Emissions Reductionsd(tpy)MethaneVOCSmall 10,05150/50 4 2 25049.8 7.7 2.175/25 4 3 17069.8 10.8 3.025/75 4 1 33029.9 4.6 1.3MediumSmall10,05150/50 10 5 5125124.6 19.2 5.375/25 10 7.5 2.5175174.5 26.9 7.525/75 10 2.5 7.57574.7 11.5 3.2Medium 32,27150/50 20 10 10249249.2 38.4 10.775/25 20 15 5349349.1 53.8 15.025/75 20 5 15149149.4 23.0 6.4MediumLarge72,39450/50 50 25 25623623.1 96.0 26.775/25 50 37.5 12.5873872.7 134.5 37.425/75 50 12.5 37.5374373.5 57.5 16.0Large 72,39450/50 100 50 501,2461246.2 192.0 53.475/25 100 75 251,7451745.4 269.0 74.825/75 100 25 75747747.0 115.0 32.0a. 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 arediaphragm and 25% are piston, etc.).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 savingsper diaphragm pump and $87 savingsper piston pump.d. Based on 3.36 tons per year of methane and 0.96 tons per year of VOC per diaphragm pump and 0.36 tons per year of methane and 0.11 tons per year of VOC perpiston pump.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document161Table 7-7. Cost of Compressor Replacement for Existing Instrument Air SystemCompressorSizeAirCapacity(scf/hour)CapitalCost($)Capital Cost+Installationa(2008)TotalCapitalCost($2012)AnnualizedCost($)LaborCost($2008)PowerCost($2008)TotalO&M($2008)TotalO&M($2012)Annual Cost($)Small135 $3,772 $5,658 $5,999 $854 $1,334 $7,340 $8,674 $9,197 $10,051Medium562 $18,855 $28,282 $29,989 $4,270 $4,333 $22,075 $26,408 $28,002 $32,271Large1,350 $33,183 $49,775 $52,779 $7,515 $5,999 $55,188 $61,187 $64,880 $72,394a. Installation cost is estimated to be 50 percent of capital cost.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 pum p 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 com bustion device are further described in Table 7-5. We estimate that capture and combustion device effici ency to be 95 percent reduction. Therefore, CH 4 

### reductions are estimated to be 3.29 tons per year for a diaphragm pump and 0.36 t ons 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 em issions by 0.91 tons per ye ar per diaphragm pump and 0.1 tons per year for a piston pu mp. Likewise, for the transmission and storage segment, we estimate that routing emissions to a combustion device will reduce CH 4 

### reductions by 3.29 tons per year per diaphragm pump and 0.36 tons per year for a pist on 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 emissi ons. 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 alrea dy have at least one existing combustion device.

7.3.4.3 Cost Impacts Routing natural gas to an existing combustion de vice or installing a new combustion device have associated capital costs and operating costs. Base d on the analysis conduct ed for the 2012 NSPS for a
combustion device to control em issions from storage vessels, 99 

### the capital cost for installing a new combustion device is $32,301 in 2008 dollars. We estima te 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 th e annualized cost of in stalling a new combustion device to $21,877 using a 7 per cent discount rate. We estim ate the annualized cost of routing emissions to an existing combustion device to be $285 using a 7 percent discount ra te. Because the gas captured is combusted there is no gas savings associat ed with use of a combustion device.

98 Ibid.
99 U.S. EPA docket ID: EPA-HQ-OAR-2010-0505-0045.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 ga s creates secondary emi ssions of hydrocarbons, NO X 

### , CO 2 

### , 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 Pneumati c 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 potent ial to reduce the emissions from natural gasdrive pumps by 100 percent if all vapor is recovered. Ho wever, the effectiveness of the gas capture system
and downtime for maintenance would re duce capture efficiency and theref ore, we estimate that routing emissions from a natural gas-driven pump to an ex isting 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 re ductions for routing gas to a VR U to be 3.29 tons per year for a diaphragm pump and 0.36 tons per year for a piston pu mp. 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 em issions to a VRU will redu ce 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 ye ar per piston pump.

7.3.5.2 Effectiveness VRUs are reliable, typically with a backup compre ssor 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) THC a CO b CO 2 c NO x d PM e Diaphragm 0.02 0.04 14 0.01 0
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### VRU. Some of these other emissi on sources can include tanks, dehydr ators, and compressors and as a result, VRUs are more common at natural gas pr ocessing plants or larg e dehydration facilities.

7.3.5.3 Cost Impacts Routing natural gas to an existing VRU or inst alling a new VRU, have both capital costs and maintenance costs. Based on the analysis conducted for the 2012 NSPS for cont rol of emissions from storage vessels 100 

### , 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 VR U is already on site, then the additional costs for routing emissions from a pump are small, as the major ity 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 ga s recovered through the VRU, we estimate an annual gas recovered as 187 Mcf per year per diaphragm pu mp 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 ar e indirect, variable and dependent on the electrical supply used to power the VRU. No ot her secondary impact s 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 evaluate d for natural gas-driven pumps included options that provided for 100 percent emissions reductions. These options in cluded replacing the pum ps 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 tec hnologies that would result in 95 percent emissions
reductions.

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### The use of instrument air systems and electric pu mps as a control alterna tive requires a consistent supply of electric power and use of solar-powered pumps and routing emi ssions to a VRU requires reliable supply of backup electri cal power. Because reliab le electric power is not considered to be universally available for production, gathering and boosting and transmi ssion and storage locations these control technologies were determined to not be technically viable op tions for those segments. Because electric power is typically availa ble at natural gas processing plants , those technologie s are considered technically viable for th e processing segment.

Based on the costs and estimated em issions 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 met hod, or the multipollutant approach, allocates costs among the pollutants that a given technology reduced (i.e., CH 4 

### and VOC). This multipollutant approach is based on estimates of the percentage reductio n expected for each pollutant.

Based on the above considerations we eval uated 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 reduc tion standard for production, gathering and boosting stations, transmi ssion stations and storage facilities.

 Regulatory Option 3. Require a 95 percent emissions reduc tion standard for production, gathering and boosting stations, transmission stations and st orage facilities only where an existing control device is available.
7.4.1 Evaluation of Re gulatory Options Regulatory Option 1 would requir e a zero emission of methane and VOC from gas-driven pumps at natural gas processing plants. To attain this emission reduction, th e 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 evalua ted 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 separa tely) 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 cons idering gas savings. With gas savings, for the use of an instrument air system at natural gas processing plan ts, the cost per ton of methane reduced was $146 andProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 VO C, we estimate the cost of control, without considering gas savings, ranged from $187 to 1,093 pe r 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 t on of VOC reduced. The range of cost per ton is dependent on the size of the system/compressor needed for the facility. We es timate the cost of control for replacement of a natura l gas-driven pump with either an elect ric pump or solar powered pumps to be between -$136 and $1,223 per ton of methane a nd 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 CH 4 

### and VOC, Regulatory Option 1 was accepted for th e 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 in strument air systems) ar e not technically viable alternatives for the production and transmission and storage segments, th e available control technologies for those segments produce a 95 percent emission reduction. Therefore, the second regulatory option would require a 95 percent reduc tion in emissions at production si tes, transmission stations and underground storage facilities. To attain this emi ssion 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 redu ctions ranged from are $3,652 to over $1 million. The
cost of control for a new combustion device was likewi se unreasonable with the cost per ton of methane ranging between $3,328 to over $1 million. Based on these cost of control values for CH 4 

### 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 contro l of emissions in all segments only where an existing control device, capable of at least 95 percent reduction in emissi ons 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 discu ssed 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 pe rcent discount rate, provi ded for an annualizedProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 reduc tions ranged from $156 to $14,250. Considering natural gas savings when a VRU is used, the cost of cont rol for methane emissions reductions is -$71 to $279 and the cost of control for VOC reductions range d from -$254 to $1,004. We found these methane costs to be reasonable and Option 3 was accepted for c ontrol of natural gas-driven pump emissions all segments. Tables 7-17 through 7-18 summarize the cost of control.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document168Table 7-9.Cost of Control for Use of Instrument Air Systems atNatural Gas Processing Plants - Single-PollutantPlant SizeCompressorCostaScenariobTotalNumberofPumpsTotal GasSavedc(Mcf)Emissions Reductionsd(tpy)Cost of control(without savings)($/ton)Cost of control(with savings)c($/ton)MethaneVOCMethaneVOCMethaneVOCSmall $10,05150/50 4 49.8 7.7 2.1 $1,309 $4,708 $1,081 $3,89075/25 4 69.8 10.8 3.0 $934 $3,360 $707 $2,54325/75 4 29.9 4.6 1.3 $2,185 $7,861 $1,957 $7,042MediumSmall$10,05150/50 10 124.6 19.2 5.3 $523 $1,883 $296 $1,06575/25 10 174.5 26.9 7.5 $374 $1,344 $146 $52725/75 10 74.7 11.5 3.2 $874 $3,144 $646 $2,325Medium $32,27150/50 20 249.2 38.4 10.7 $840 $3,023 $613 $2,20575/25 20 349.1 53.8 15.0 $600 $2,158 $373 $1,34025/75 20 149.4 23.0 6.4 $1,403 $5,048 $1,175 $4,229MediumLarge$72,39450/50 50 623.1 96.0 26.7 $837 $3,011 $527 $1,89575/25 50 872.7 134.5 37.4 $558 $2,007 $311 $1,11925/75 50 373.5 57.5 16.0 $1,674 $6,022 $1,031 $3,711Large $72,39450/50 100 1246.2 192.0 53.4 $418 $1,505 $150 $53975/25 100 1745.4 269.0 74.8 NA - Beyond Capacity25/75 100 747.0 115.0 32.0 $837 $3,011 $402 $1,446a. 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 arediaphragm and 25% are piston, etc.).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 savingsper diaphragm pump and $87 savingsper piston pump.d. Based on 3.36 tons per year of methane and 0.96 tons per year of VOC per diaphragm pump and 0.36 tons per year of methane and 0.11 tons per year of VOC perpiston pump.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document169Table 7-10.Cost of Control for Use of Instrument Air Systems atNatural Gas Processing Plants - Multi-pollutant MethodPlant SizeCompressorCostaScenariobTotalNumberofPumpsTotal GasSavedc(Mcf)Emissions Reductionsd(tpy)Cost of Control(without savings)($/ton)Cost of Control(with savings)c($/ton)MethaneVOCMethaneVOCMethaneVOCSmall $10,05150/50 4 49.8 7.7 2.1 $654 $2,354 $541 $1,94575/25 4 69.8 10.8 3.0 $467 $1,680 $353 $1,27125/75 4 29.9 4.6 1.3 $1,093 $3,930 $979 $3,521MediumSmall$10,05150/50 10 124.6 19.2 5.3 $262 $942 $148 $53375/25 10 174.5 26.9 7.5 $187 $672 $73 $26325/75 10 74.7 11.5 3.2 $437 $1,572 $323 $1,163Medium $32,27150/50 20 249.2 38.4 10.7 $420 $1,512 $307 $1,10375/25 20 349.1 53.8 15.0 $300 $1,079 $186 $67025/75 20 149.4 23.0 6.4 $702 $2,524 $588 $2,114MediumLarge$72,39450/50 50 623.1 96.0 26.7 $418 $1,505 $263 $94875/25 50 872.7 134.5 37.4 $279 $1,004 $156 $55925/75 50 373.5 57.5 16.0 $837 $3,011 $516 $1,855Large $72,39450/50 100 1246.2 192.0 53.4 $209 $753 $75 $26975/25 100 1745.4 269.0 74.8 NA - Beyond Capacity25/75 100 747.0 115.0 32.0 $418 $1,505 $201 $723a. 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 arediaphragm and 25% are piston, etc.).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 savingsper diaphragm pump and $87 savingsper piston pump.d. Based on 3.36 tons per year of methane and 0.96 tons per year of VOC per diaphragm pump and 0.36 tons per year of methane and 0.11 tons per year of VOC perpiston pump.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document170Table 7-11.Cost of Control for Replacement with Solar-Powered or Electric Pumps at Natural Gas Processing Plants - SinglepollutantType ofPumpControlOptionEmission Factor(tpy/pump)AnnualizedCost($)Natural GasCost of Control($/ton)EmissionFactor(scf/h)Saved(Mcf/yr)Value($)without savingswith savingsMethaneVOCMethaneVOCMethaneVOCDiaphragm Electrica3.46 0.96 4,175 22.45 197 $786 $276 $994 $49 $175Diaphragm Solar 3.46 0.96 $2,000 22.45 197 $786 $92 $330 ($136) ($489)Piston Electrica0.38 0.11 $4,175 2.48 22 $87 $1,452 $5,016 $1,223 $4,235Piston Solar 0.38 0.11 $2000 2.48 22 $87 $834 $2,882 $605 $2,091a. For electric pumps, annual cost assumes a5.0 BHP electric pump as reported in NGSLL "Replacing Gas-Assisted Glycol Pumps with Electric Pumps". Assumesinstallation is 10% of the capital cost.Table 7-12.Cost of Control for Replacement with Solar-Powered orElectric Pumps at Natural Gas Processing Plants - Multipollutant MethodType ofPumpControlOptionEmission Factor(tpy/pump)AnnualizedCost($)Natural GasCost of Control($/ton)EmissionFactor(scf/h)Saved(Mcf/yr)Value($)without savingswith savingsMethaneVOCMethaneVOCMethaneVOCDiaphragm Electrica3.46 0.96 $4,175 22.45 197 $786 $138 $497 $24 $88Diaphragm Solar 3.46 0.96 $2,000 22.45 197 $786 $46 $165 ($68) ($244)Piston Electrica0.38 0.11 $4,175 2.48 22 $87 $726 $2,508 $1,337 $2,112Piston Solar 0.38 0.11 $2,000 2.48 22 $87 $417 $1,1441 $720 $1,046a. For electric pumps, annual cost assumes a5.0 BHP electric pump as reported in NGSLL "Replacing Gas-Assisted Glycol Pumps with Electric Pumps". Assumesinstallation is 10% of the capital cost.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document171Table 7-13.Cost of Control for Routing Gas-Driven PumpEmissions to a VRU - Single-pollutant MethodPump Type/SegmentEmission Reductions(tpy/pump)AnnualizedCost($)Natural GasCost of Control($/ton)EmissionFactor(scf/h)Saved(Mcf/yr)Value($)without savingswith savingsMethaneVOCMethaneVOCMethaneVOCDiaphragm PumpsProduction3.29 0.91 $24,755 22.45 187 $749 $7,531 $27,094 $7,304 $26,275Processing3.29 0.91 $24,755 22.45 187 $749 $7,531 $27,094 $7,304 $26,275Transmission3.29 0.09 $24,755 22.45 187 $749 $7,531 $271,888 $7,531 $271,888Storage3.29 0.09 $24,755 22.45 187 $749 $7,531 $271,888 $7,531 $271,888Piston PumpsProduction0.36 0.10$24,7552.48 21 $84 $68,574 $246,697 $68,343 $245,864Processing0.36 0.10$24,7552.48 21 $84 $68,574 $246,697 $68,343 $245,864Transmission0.36 0.01$24,7552.48 21 $84 $68,574 $2,475,608 $68,574 $2,475,608Storage0.36 0.01$24,7552.48 21 $84 $68,574 $2,475,608 $68,574 $2,475,608Note: No gas savings is attributed to transmission and storage.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document172Table 7-14.Cost of Control for Routing Gas-Driven PumpEmissions to a VRU - Multi-Pollutant MethodPump Type/SegmentEmission Reductions(tpy/pump)AnnualizedCost($)Natural GasCost of Control($/ton)EmissionFactor(scf/h)Saved(Mcf/yr)Value($)without savingswith savingsMethaneVOCMethaneVOCMethaneVOCDiaphragm PumpsProduction3.29 0.91$24,75522.45 187 $749 $3,766 $13,547 $3,254 $11,705Processing3.29 0.91$24,75522.45 187 $749 $3,766 $13,547 $3,254 $11,705Transmission3.29 0.09$24,75522.45 187 $749 $3,766 $135,944 $3,766 $135,944Storage3.29 0.09$24,75522.45 187 $749 $3,766 $135,944 $3,766 $135,944Piston PumpsProduction0.36 0.10$24,7552.48 21 $84 $34,287 $123,348 $34,171 $122,932Processing0.36 0.10$24,7552.48 21 $84 $34,287 $123,348 $34,171 $122,932Transmission0.36 0.01$24,7552.48 21 $84 $34,287 $1,237,804 $34,287 $1,237,804Storage0.36 0.01$24,7552.48 21 $84 $34,287 $1,237,804 $34,287 $1,237,804Note: No gas savings is attributed to transmission and storage.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document173Table 7-15.Estimated Cost of Control for Emission Reductions fromRouting Gas-Drive Pump Emissions to a New CombustionDevice - Single-Pollutant MethodSegmentType of PumpEmissions Reductions(tons/yr-pump)Annualized Cost($2012)Cost of Control($/ton)MethaneVOCMethaneVOCProduction Diaphragm 3.287 0.914 $21,877 $6,656 $23,944Processing Diaphragm 3.287 0.914 $21,877 $6,656 $23,944Transmission Diaphragm 3.287 0.091 $21,877 $6,656 $240,279Storage Diaphragm 3.287 0.091 $21,877 $6,656 $240,279Production Piston 0.361 0.100 $21,877 $60,602 $218,017Processing Piston 0.361 0.100 $21,877 $60,602 $218,017Transmission Piston 0.361 0.010 $21,877 $60,602 $2,187,805Storage Piston 0.361 0.010 $21,877 $60,602 $2,187,805Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document174Table 7-16.Estimated Cost of Control for Emission Reductions fromRouting Gas-Drive Pump Emissions to a New CombustionDevice - Multi-pollutant MethodSegmentType of PumpIndividual Pneumatic PumpEmissions Reductions(tons/yr-pump)Annualized Cost($2012)Cost of Control($/ton)MethaneVOCMethaneVOCProduction Diaphragm 3.287 0.914 $21,877 $3,328 $11,972Processing Diaphragm 3.287 0.914 $21,877 $3,328 $11,972Transmission Diaphragm 3.287 0.091 $21,877 $3,328 $120,140Storage Diaphragm 3.287 0.091 $21,877 $3,328 $120,140Production Piston 0.361 0.100 $21,877 $30,301 $109,009Processing Piston 0.361 0.100 $21,877 $30,301 $109,009Transmission Piston 0.361 0.010 $21,877 $30,301 $1,093,902Storage Piston 0.361 0.010 $21,877 $30,301 $1,093,902Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document175Table 7-17.Cost of Control for Routing Gas-Driven Pump Emissions to an Existing Combustion Device or VRU- Single-pollutant MethodPump Type/SegmentEmission Reductions(tpy/pump)AnnualizedCost($)Natural GasCost of Control($/ton)EmissionFactor(scf/h)Saveda(Mcf/yr)Value($)without savingswith savingsaMethaneVOCMethaneVOCMethaneVOCDiaphragm PumpsProduction3.29 0.91 $285 22.45 187 $749 $87 $312 ($141) ($507)Processing3.29 0.91 $285 22.45 187 $749 $87 $312 ($141) ($507)Transmission3.29 0.09 $285 22.45 187 $749 $87 $3,130 $87 $3,130Storage3.29 0.09 $285 22.45 187 $749 $87 $3,130 $87 $3,130Piston PumpsProduction0.36 0.10 $285 2.48 21 $84 $789 $2,840 $558 $2,007Processing0.36 0.10 $285 2.48 21 $84 $789 $28,501 $558 $2,007Transmission0.36 0.01 $285 2.48 21 $84 $789 $28,501 $789 $28,501Storage0.36 0.01 $285 2.48 21 $84 $789 $28,501 $789 $28,501a. Applies to VRU only. There is no gas savings with a combustion device.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document176Table 7-18.Cost of Control for Routing Gas-Driven Pump Emissions to an Existing Combustion Device or VRU- Multi-Pollutant MethodPump Type/SegmentEmission Reductions(tpy/pump)AnnualizedCost($)Natural GasCost of Control($/ton)EmissionFactor(scf/h)Saveda(Mcf/yr)Value($)without savingswith savingsaMethaneVOCMethaneVOCMethaneVOCDiaphragm PumpsProduction3.29 0.91 $285 22.45 187 $749 $43 $156 ($71) ($254)Processing3.29 0.91 $285 22.45 187 $749 $43 $156 ($71) ($254)Transmission3.29 0.09 $285 22.45 187 $749 $43 $1,565 $43 $1,565Storage3.29 0.09 $285 22.45 187 $749 $43 $1,565 $43 $1,565Piston PumpsProduction0.36 0.10 $285 2.48 21 $84 $395 $1,420 $279 $1,004Processing0.36 0.10 $285 2.48 21 $84 $395 $1,420 $279 $1,004Transmission0.36 0.01 $285 2.48 21 $84 $395 $14,250 $395 $14,250Storage0.36 0.01 $285 2.48 21 $84 $395 $14,250 $395 $14,250a. Applies to VRU only. There is no gas savings with a combustion device.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### 7.4.2 Nationwide Impacts of Selected Regulatory Options We calculated the nationwide impacts of the se lected options by considering the estimated affected population for each of the target years, the estimated emissi ons 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 pres ented above, we estimate there will be no new pneumatic pumps installed in the natural gas processi ng 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 year s 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 2 025, we determined the affected population as those affected facilities from the years 2020 through an d including 2025. Therefore, we estimate that 17,760 new pneumatic pumps will be installed in the pr oduction segment by 2025, half of which will be diaphragm pumps and half will be piston pumps.
Based on those activity numbers, the nationw ide methane emission reductions in 2020 are estimated to be 4,865 tons per year of methane an d 1,352 tons per year of VOC from diaphragm pumps and 534 tons per year of methane and 149 tons pe r 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 pr ojected year 2025, we estim ate 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 a nnualized cost for routing pump emissions either to a combustion device or a VRU would be $285. Base d on the estimated popul ation 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 su mmarizes the nationwide impacts.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 summa rizes the nationwide sec ondary emissions for the projected year 2020 and 2025 for Option 3.
Table 7-20. Nationwide Secondary Impacts from Pn eumatic 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) THC a CO b CO 2 c NO x d PM e Projected Year 2020 Production 25 66 23,616 12 0
Projected Year 2025 Production 150 396 141,696 72 0Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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## 8.0 COMPRESSORS Compressors are mechanical devices that increa se the pressure of na tural gas and allow the natural gas to be transported from the production s ite, through the supply chain, and to the consumer. The types of compressors that are used by the oil and na tural gas industry as prime movers are reciprocating and centrifugal compressors. This chapter discusses th e 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, em ission reductions, and secondary impacts. Finally, this chapter discusses considerati ons in developing regulator y 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 ga s is in the cylinder. The compresso r rod packing system consists of a series of flexible rings that cr eate a seal around the piston rod to pr event gas from escaping between the rod and the inboard cylinder head. However, over time, during operation of th e 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 impe ller to increase the velocity of the gas where it is directed to a divergent duct s ection that converts th e velocity energy to pressure energy. These compressors are primarily used for continuous, stationa ry transport of natural ga s in the processing and transmission systems. Many centrifugal compressors us e wet (meaning oil) seals around the rotating shaft to prevent natural gas from escaping where the co mpressor shaft exits the compressor casing. The wet
seals use oil which is circulated at high pressure to form a barrier ag ainst compressed natural gas leakage. The circulated oil entrains and absorbs some compresse d natural gas which is rel eased to the atmosphere during the seal oil recircul ation process. Alternativel y, dry seals can be used in place of wet seals in centrifugal compressors. Dry seal s prevent leakage by using the opposing force created by hydrodynamicProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 beca use they are not in contact with each other. Therefore, operation an d maintenance costs are typically lo wer for dry seals in comparison to
wet seals.



### 8.2 Emissions Data and Em issions Factors
8.2.1 Summary of Major Studies and Emissions Factors

There are a few studies that have been conducted th at 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- 2012 a EPA 2014 Nationwide X
GHG Mandatory Reporting Rule and TSD b EPA 2013 Nationwide X Inventory of GHG Emissions and Sinks: 1990- 2012 c EPA 2014 Nationwide/ Regional X

CH 4 Emissions from the Natural Gas Industry d GRI/EPA 1996 Nationwide X
Natural Gas STAR Program e,f EPA 1993-2010 Nationwide X X Natural Gas Industry CH 4 Emission Factor Improvement Study g URS Corporation, UT Austin, and U.S. EPA 2011 None Emission Factors Only
Characterizing Pivotal Sources of CH 4 Emissions from Natural Gas Production: Summary and Analysis of API and ANGA Survey Responses h, i API/ANGA 2012 Regional X h

Economic Analysis of CH 4 Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries j 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 CH 4 and CO 2 Emissions from Natural Gas Systems. GHG Inventory: Emission and Sinks 1990-2008. Washington, DC. and U.S EPA. Methodology for Estimating CH 4 and CO 2 Emissions from PetroleumProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

181 Systems. GHG Inventory: Emission and Sinks 1990-2008. Washington, DC. d. National Risk Management Research Laboratory. GRI/EP A 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/X A_83376101_Final_Report.pdf. h. API and America’s Natural Gas Alliance (ANGA). 2012. Char acterizing 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 Em issions 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 Ce ntrifugal Compressor Emissions The methodology for estimating emission from reci procating compressor rod packing was to use
the CH 4 

### emission factors referenced in the EPA/GRI study 101 

### and the CH 4 

### -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 pe r cylinder (Mscf/cyl), and were multiplied by the average number of cylinder per reciprocating compre ssor at each oil and gas indust ry segment. The volumetric CH 4 

### emission rate was converted to a mass emissi on rate using a density of 41.63 lbs of CH 4 

### per Mcf. This
conversion factor was de veloped assuming that CH 4 

### is an ideal gas and us ing the ideal gas law to calculate the density. A summary of the CH 4 

### emission factors is presente d in Table 8-2. Once the CH 4 

### emissions were calculated, the ratio of VOC to CH 4 

### was used to estimate VOC emissions. The specific VOC-to-CH4 ratios used for this analysis were 0.278 lbs VOC per pound of CH 4 

### for the production and processing segments, and 0.0277 lbs VOC per pound of CH 4 

### 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 an d dry seals are based on data used in the GHG Inventory 103 

### . The wet seals CH 4 

### emission factor was calculated ba sed on a sampling of 48 wet seal centrifugal compressors. The dry seal CH 4 

### emission factor was based on data collected by the Natural Gas STAR Program. The CH 4 

### emissions were converted to VOC a nd HAP emissions using the same gas composition ratios that were us ed 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 CH 4 and CO 2 Emissions from Petroleum Syst ems. GHG Inventory: Emission and Sinks: 1990-2012. Washington, DC. 2014.
104 IbidProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### Since publication of the white paper, additional data have become available on compressor emissions in transmission and storage, includ ing reporting year 2013 data from GHGRP, and new
measurement data from Subramanian et al. 2015. Thes e data confirm the signifi cant emissions from these sources, but indicate that emissions levels differ from those a ssumed in this analysis. In the 2013 GHGRP transmission and storage data set, reported emissions from recipr ocating compressors are 2,247,626 tons
CO 2 

### e of methane, and reported emissions from centrifugal compre ssors are 597,715 tons CO 2 

### e of methane. The Subramanian study, compared tota l average methane emissions per compressor in transmission and storage for bot h reciprocating and centrifugal co mpressors to those in the GHG Inventory, and found that the GHG Invent ory had higher average emissions.

Table 8-2. Methane Emission Factors for Re ciprocating and Centrifugal Compressors

Compresso

r Station Reciprocating Compressors Centrifugal Compressors CH 4 Emission Factor (scf/hr-cylinder) Average Number of Cylinders Pressurized Factor a Wet Seal CH 4 Emission Factor (scf/minute) Dry Seals CH 4 Emission Factor (scf/minute) Pressurized Factor a

Transmission 57 b 3.3 79.1% 47.7 d 6 d 30.0 d
Storage 51 c 4.5 67.5% 47.7 d 6 d 22.4 d 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 CH 4 and CO 2 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) CH 4 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 0.407Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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 emissi on factor data presented in Table 8-3. A summary of the number of new reciprocati ng 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 co mpressors, and dry seal centrifugal compressors installed in a given year was estim ated 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 latte r year (e.g., number of new compresso rs installed during 2012 equals the compressors reported in 2012 minus the compresso rs 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 numb er. The results of this analysis are shown in Table 8-4.

105 See footnote 6.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### Table 8-4. Approximate Number of New Compressors in the Transmis sion and Storage Segment in a Typical Year a

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 co mpressors 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 Ne w Reciprocating and Ce ntrifugal Compressors

Compressor Location/Compressor Typ e Nationwide Baseline Emissions (tpy) CH 4 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 reduc ing emissions from reciprocating compressors include control techniques that lim it the leaking of natura l gas past the piston rod packing. This includes replacement of the compressor rod packing, repl acement of the piston rod, and the refitting or realignment of the piston rod.
The replacement of the rod packing is a ma intenance 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 pist on rod. Regular replacement of these rings reduces
CH 4 

### and VOC emissions. Therefore, this control techni que was determined to be an appropriate option for reciprocating compressors.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

185 

### Like the packing rings, piston rods on reciprocating compressors al so deteriorate. Piston rods, however, wear more slowly than packi ng 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 agains t 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 seal s, thereby shortening the li fe of the piston rod and the packing seal. Replacing or upgr ading the rod can reduce recipr ocating 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 di scretion, when to replace the rod and hence, does not consider this contro l technique to be a prac tical control option for reciprocating compressors. A summary of these t echniques 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 captu re 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 us es rings to prevent the escape of natural gas across the rota ting shaft. This control technique was determined to be a viable option for reducing emission fr om centrifugal compressors.
For centrifugal compressors equipped with wet seals, a combustion device was considered to be a reasonable option for reducing emissions from centrif ugal compressors. Centrifugal compressors require seals around the rotating shaft to pr event 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 s eals use oil, which is circulated under high pressure between three rings around the co mpressor shaft, forming a barrier against the compressed gas leakage. The center ring is attached to the rotating shaft, wh ile 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” r ubber 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

186 

### seal oil/gas interface, thus contaminating the seal oil. Seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing te chniques) 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 r od packing consists of a series of fl exible rings that fit around a shaft to create a seal against leakage. As the rings wear , they allow more compresse d 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 “nos e gasket” around the packing case, between the packing cups, and between the rings and sh aft. 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 emi ssion factors (as presented in Table 8-2) and the average emission factor for newly installed rod packing. This calcu lation, shown in the Equation 1 below, was performed for the tr ansmission and storage segment.

Equation 1 

###  

6 & 10 8760   


 O C E E Comp R New B G PTS New PTS where:
R PTS = Potential CH 4 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. E G&B = Methane emission factor for transmission or storage compressors in Table 8-2, in cubic feet per hour per cylinder. E

New =Average emissions from a newly installed rod pack ing, assumed to be 11.5 cubic feet per hour per cylinder 107 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 aver age transmission or storage compressor is in the operating and standby pressurized modes, 79.1%, 67.5% respectively. 8760 = Number of days in a year. 10 6 = Number of cubic feet in a million cubic feet.

107 Ibid.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

187 

### A summary of the potential em ission reductions for reciproc ating compressor rod packing replacement in the transmission and storage segment is presented in Table 8-6. The emissions of VOC were estimated using the CH 4 

### emissions calculated above and the CH 4 

### -to-VOC- ratio developed for each of the segments in the gas compos ition analysis conducted for the NSPS. 108



### Table 8-6. Estimated Annual Reciprocating Compre ssor Emission Reduction s from Replacing Rod Packing

Compressor

Location Number of New Sources Per Year Individual Compressor Emission Reductions (tons/compressor-year) Nationwide Emission Reductions (tpy) CH 4 VOC CH 4 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 comp ressor rod packing were obtained from a Natural
Gas STAR Lessons Learned document 109 

### which estimated the cost to re place 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 reci procating compressors occu rs on average every four years based on industry information fr om 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 percen tage that the reciprocating compresso rs are pressurized for all of the new sources. This percentage of hours is, on average, the number of hours pe r 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 aver age 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

188 

### 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 Tabl e 8-2. The calculated years were assumed to be the equipment life of the compressor rod packing and were used to calculate the capit al 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 pack ing cost of $1,712 and the average number of cylinde rs per segment as presented in Table 8-2. The annual costs were calcu lated using the capital cost and the capital recovery
factors.
The cost per ton of emissions reduced was then ca lculated in two ways. Th e first method, or singlepollutant approach, allocated all of the costs to each pollutant se parately. The second method, or multipollutant approach, allocated cost s among the pollutants that a give n technology reduced (i.e., CH4 and VOC). The multi-pollutant approach was based on estimat es of the percentage reduction expected for each pollutant. A summary of the capital a nd 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 we re 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 th at is compressed at their compressor stations.
Table 8-7. Cost of Control for Reciprocatin g 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) CH 4 VOC CH 4 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 replacemen t is an option that prevents the escape of natural gas from the piston rod. No wastes shoul d 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 co sts were included for monitoring because the rod packing is replaced based on operating hours or time since the last replacement.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

189 

### 8.4.3 Centrifugal Compressor Dry Seals
8.4.3.1 Description Centrifugal compressor dry s eals operate mechanically unde r the opposing force created by hydrodynamic grooves and springs. The hydrodynamic groove s are etched into the surface of the rotating ring affixed to the compressor shaft. When the compressor is not rotati ng, the stationary ring in the seal housing is pressed agains t the rotating ring by spri ngs. When the compressor shaft rotates at high speed, compressed gas has only one pathway to l eak 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 ga s 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 w ith each other, and therefor e, do not wear or need lubrication. O-rings seal the stationary rings in the seal case.
Dry seals substantially reduce gas emissions comp ared to wet seals. At the same time, they significantly reduce operating costs a nd enhance compressor efficiency co mpared to wet seals. Economic and environmental benefits of dry seals include:

 Gas Leak Rates. During normal operation, dr y seals leak at a rate of 6 scfm CH 4 

### 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 ve nted to the atmosphere, bringing the total leakage
rate for tandem wet seals to 47.7 scfm CH 4 

### 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 pow er losses. Wet seal systems require 50 to 100 kilowatt (kW) per hour, while dry seal syst ems 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 fe wer 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/doc uments/best_paper_award.pdf
113 See footnote 6.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

190 

### higher overall reliability and less compressor downtime.

 Lower Maintenance. Dry seal systems have lo wer 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 co ntamination of the gas and degradation of the pipeline.

8.4.3.2 Emissions Reduction Potential The emissions reductions of the dry seal compresso rs was calculated by s ubtracting the dry seal emissions from the emissions from a centrifugal co mpressor 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 a nd 22.4 percent for storage centrifugal compressors. The operating factors are used to account for the per cent of time in a year th at 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 fr om 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 Compre ssor 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)
CH 4 VOC CH 4 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 dr y 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 centrifuga l 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

191 

### only about 1 to 3 percent of the total cost of th e compressor. The price of a brand new natural gas transmission pipeline centrif ugal 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 di fference 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 calcula ted as the capital recovery of th is capital cost assuming a 20-year equipment life and 7 percent interest which cam e to $7,482 per compressor. The Natural Gas STAR Program estimated that the annual operation and main tenance savings from the installation of dry seal compressor is $88,300 in comparison to wet seal compre ssor. 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 co sts 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 CH 4 

### and VOC cost of control for the dry seal compressor option. There is no gas savings cost benefits for transmissi on 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) CH 4 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 wa stes should be created, no wastew ater generated, and no electricity needed. Therefore, there are no secondary impacts expected due to the inst allation of dry seals on centrifugal compressors.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

192 

### 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 combusti on device or capture the em issions and route them to a fuel system. A wet seal system uses oil that is circulated unde r high pressure between three rings around the compressor shaft, forming a barrier against the compressed gas. The cen ter ring is attached to the rotating shaft, while the two ri ngs on each side are stationary in the seal housing, pressed against a thin film of oil flowing between the rings to both lubr icate and act as a leak barrier. Compressed gas
becomes absorbed and entrained in the fluid barrier and is removed using a h eater, flash tank, or other degassing technique so that the oil ca n be recirculated back to the wet seal. The removed gas is either combusted or released to the atmosphere. The control t echnique investigated in th is 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 comb ustion 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 degassi ng process would be directed to a combustion device that achieves 95 percent reduction of CH 4 

### , 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 reduc tions is presented in Table 8-10.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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### Table 8-10. Estimated Annual Centrifugal Compresso r 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) CH 4 VOC CH 4 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 de vice (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-p ollutant 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 allo cation was based on estimates of the percentage reduction expected for each pollutant. The CH 4 

### and VOC cost of control for the wet seals routed to a combustion device option is also show n 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 Compre ssor 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 CH 4 VOC CH 4 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

194 

### 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, (NO X 

### , CO 2 

### , and CO emissions. A summary of the estimated secondary emi ssion 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 positiv e 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. Ther efore these types of comp ressors would be subject
to the NSPS at the time of in stallation. The following Regulat ory options were evaluated:

 Regulatory Option 1. Require replacement of th e reciprocating compressor rod packing based on 26,000 hours of operation while the compressor is pressurized.

 Regulatory Option 2. Require all centrifugal compresso rs 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 Regulat ory Options The first regulatory option for replacement of the reciprocating compre ssor rod packing based on the number of hours that the compressor operates in the pressurized mode was described in Section 8.4.1.
The CH 4 

### and VOC cost of control for reciprocating co mpressors at transmission stations is $81 and $2,910 per ton, respectively. The CH 4 

### and VOC cost of control for reci procating compressors at storage Compressor Location Secondary Impacts from Wet Seals Routed to a Combustion Device (tpy) THC a CO b CO 2 c NO x d PM e
Transmission 0 0 0 0 0 Storage 0.58 1.54 550 0.28 0.01Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

195 

### facilities is $95 and $3,434 per ton, respectively. Based on these co st of control values for CH 4 

### , 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 CH 4 

### and VOC cost of emissions reductions for dry seals compressors was calculated to be $55/ton and $1,974/ton respectively for centrifugal comp ressors located at transmission facilities, not including the savings from operation and maintenance costs. When those savings were considered the
CH 4 

### and VOC cost of control was calculat ed to be -$627/ton and -$22,642/ton. The CH 4 

### and VOC cost of control for dry seal compressors was calcu lated to be $73/ton and $2,643/ton respectively for centrifugal compressors located at storage facilitie s, not including the savings from operation and maintenance costs. When those savings were considered the CH 4 

### and VOC cost of control was calculated to be -$840/ton and -$30,324/ton. However, commen ters 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 so me existing compressors due to housing design or operational requirements. Therefor e, Regulatory Option 2 was reject ed as a regulatory option for centrifugal compressors located at tr ansmission or storage facilities.
The third regulatory option would al low the use of wet seals if th e recovered gas emissions were
routed to a combustion device or another useful process. The CH 4 

### and VOC cost of control for routing emissions from a wet seal system to a combus tion device was calculated to be $767/ton and $27,705/ton respectively for centrifugal compressors lo cated at transmission facilities. The CH 4 

### and VOC cost of control for routing emissions from a wet seal syst em to a combustion device was calculated to be $1,028/ton and $37,105/ton respectively fo r centrifugal compressors located at transmission facilities. However, facilities may already ha ve a combustion device operating at the facility or would route the captured gas back to a useful process rather than flar ing it. Those facilities would not incur the additional capital cost and operation and maintenance cost s of the flare. For those facilities the CH 4 

### and VOC cost of control were calculated to be $22/ton and $804/ton respectively for transmi ssion facilities and $30/ton and $1,076/ton respectively for storag e facilities. Based on these cost of control values, Regulatory Option 3 was accepted for the tran smission 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 industryProposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

196 

### segment. Regulatory Option 1 is estimated to aff ect 24 reciprocating compressors at transmission facilities and 43 recipro cating compressors at underground stor age 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 st orage facility). The number of affected centrifugal compressors is low because the historical rate of gr owth in the overall number of wet seal centrifugal compressors in the segment has been low, indica ting few new compressors are being installed. In addition, most new centrifugal compressors are expected to use dry seals, whic h 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 seconda ry combustion-related emissions from Option 2 are
summarized in Table 8-15.Proposed 40 CFR Part 60 subpart OOOOaBackground Technical Support Document197Table 8-13. Nationwide Cost Impacts for Regulatory Option 1CompressorLocationNumber of New SourcesPer YearNationwide Emission Reductions(tpy)Total Nationwide CostsCH4VOCCapital Cost($)Annualized Cost($/year)Base Year 2012 and Projected Year 2020Transmission 24 520 14.4 $135,606 $41,941Storage 43 939 26 $331,310 $89,301Projected Year 2025Transmission 144 3,122 87$813,636 $251,646Storage 258 5,634 156$1,987,860$535,803Table 8-14. Nationwide Cost Impacts for Regulatory Option 3CompressorLocationNumber ofNew SourcesPer YearNationwide EmissionReductions(tpy)Nationwide CostsCH4VOCCapital CostNew CDa($)Capital CostExisting CDb($)Annual CostNew CDa($/year)Annual CostExisting CDb($/year)Base Year 2012 and Projected Year 2020Transmission 0 0 0 $0 $0 $0 $0Storage 1 111 3 71,783 $23,252 $114,146 $3,311Projected Year 2025Transmission 0 0 0 $0 $0 $0 $0Storage 6 666 19$430,697 $139,512.28$684,874 $19,863a. 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

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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) THC a CO b CO 2 c NO x d PM e 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 0.06Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

199 

## 9.0 OTHER POTENTIAL IMPACTS
The following sections describe impacts potentially realized as a result of the implementation of regulatory options discussed in th e sections above. Specifically, ma ny of the options discussed have potential to realize natural gas savi ngs based on the capture of natural gas that woul d have otherwise been emitted or combusted. This natural gas savings can resu lt 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 resu lt of the reductions in the emissi ons of natural gas. Finally, since
CH 4 

### is known to contribute to global warming, reducing CH 4 

### emissions has the net effect of reducing contribution of the oil and gas industry to global wa rming. Consistent with th e GHG Inventory, the global warming potential is discussed here as CO 2 

### e of CH 4 

### . 

### 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 othe rwise been vented or combusted. With respect to the regulatory optio ns presented above, there are seve ral 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 averag e annual gas saved would be 38 Mcf for oil wells, 158 Mcf for gas wells, 1,222 Mcf for gathering an d 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.Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

200 

### Based on the above per unit natura l gas savings and the new source activity counts anticipated for the projected years 2020 and 2025 for the affected facili ties, we calculated the nationwide gas savings for each of the regulatory options discussed in the sec tions above for the projected years 2020 and 2025. Table 9-1 presents the gas savings we estima te for these affected facilities.

Table 9-1. Estimated Nationwide Natural Gas Savings for Selected Regulatory Options

Affected Facility Number of Affected Facilities Subject to NSPS a 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 wi ll have potential for gas savings).Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

201 

### 9.2 Reductions of HAP and CO 2 

### e A potential benefit of emissions reductions for th e affected facilities under the NSPS is the reduction of HAP as a result of reduction of the gas th at contains HAP. For the purposes of the NSPS, we estimate HAP emissions by a pplying a ratio to the CH 4 

### 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-CH 4 

### ratios used for the various affected facilities in the various segments.

Table 9-2. HAP-to-CH 4 

### Ratios Used to Estimate HAP Emissions

Segment Affected Facility HAP-to-CH 4 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 CH 4 

### emissions reductions estimated in the ab ove sections for the respective affected facilities and regulatory options, we estimated the HAP emissions. Table 9-3 summarizes the HAP
emissions calculated for each affect ed facility and regulatory option.

Because CH 4 

### is of concern for global warming effect s, we also calculated the global warming potential expressed as CO 2 

### e for the CH 4 

### reductions from the proposed regulatory options. For the purposes of this analysis, one ton of CH 4 

### is equal to 25 tons of CO 2 

### e. We have converted the CO 2 

### e values to metric tonnes consistent with the presentation of CO 2 

### e 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

202 

### Table 9-3. HAP and CO 2 

### e Reductions for Selected Regulatory Options

Affected Facility Number of Sources Subject to NSPS Nationwide Emission Reductions CH 4 (tpy) VOC (tpy) HAP (tpy) CO 2 e (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 7.3 201,372Proposed 40 CFR Part 60 subpart OOOOa Background Technical Support Document

203 Affected Facility Number of Sources Subject to NSPS Nationwide Emission Reductions CH 4 (tpy) VOC (tpy) HAP (tpy) CO 2 e (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