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EO12866_Oil and Gas CTG 2060 - ZA22 Guidance Document and Mod el Rule Proposed 2015071 5



# Control Techniques Guidelines fo **r the Oil and Natural Gas Source Category**  **(Draft)*****E.O. 12866 Review

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iii **EPA -**  **453/P -**  **15 -**  **001** July 2015



## Control Techniques Guidelines fo **r the Oil and Natural Gas Source Category**  **(Draft)**

U.S. Environmental Protection Agency Office of Air and Radiation Office of Air Quality

Planning and Standards Sector Policies and Programs Division Research Triangle Park, North Carolina***E.O. 12866 Review

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iv **DISCLAIMER** This report has been reviewed b y EPA’s Office of Air Quality Planning and Standards and has been approved for publication. Mention of trade names or commercial products is not intended to constitute endorsement or recommendation for use.***E.O. 12866 Review

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v 

### TA **BLE OF CONTENTS**  1.0 IN TRODUCTION ................................ ................................ ................................ .......................... 1 - 1 2.0 BACKGROUND AND OVERVIEW ................................ ................................ ............................ 2 - 1 2.1 New Source Performance Standards ................................ ................................ .............. 2 - 1 2.1.1 Statutory

Authority ................................ ................................ ................................ . 2 - 1 2.1.2 ONG Source Category NSPS Regulatory

History ................................ .................. 2 - 2 2.2 CTG ................................ ................................ ................................ ................................ 2 - 4 2.3 State and L ocal Regulations ................................ ................................ ........................... 2 - 4 2.4 Development of this Guideline ................................ ................................ ....................... 2 - 7 3.0 OVERVIEW OF THE ONG SOURCE CATEGORY AND SOURCES SELECTED FOR RACT RECOMMENDATIONS ................................ ................................ ................................ .... 3 - 1 3.1 Overview of the ONG Sector ................................ ................................ ......................... 3 - 1 3.2 Sources Selected For RACT Recommendations ................................ ............................ 3 - 5 4.0 STORAGE VESSEL S ................................ ................................ ................................ .................... 4 - 1 4.1 Applicability ................................ ................................ ................................ ................... 4 - 1 4.2 Process Description and Emission Sources ................................ ................................ .... 4 - 1 4.2.1 Process Description ................................ ................................ ................................ . 4 - 1 4.2.2 Emissions Data ................................ ................................ ................................ ........ 4 - 2 4.3 Available Controls and Regulatory Approaches ................................ ............................ 4 - 6 4.3.1 Available VOC Emission Control Options ................................ ............................. 4 - 6 4.3.2 Existing Federal, State and L ocal Regulations ................................ ..................... 4 - 16 4.4 Recommended RACT Level of Control/Impacts ................................ ......................... 4 - 19 4.5 Factors to Consider in Developing Storage Vessel Compliance Procedures ............... 4 - 21 4.5.1 Compliance Recommendations When Using a Control Device ........................... 4 - 21 5.0 COMPRESSORS ................................ ................................ ................................ ............................ 5 - 1 5.1 Applicability ................................ ................................ ................................ ................... 5 - 1 5.2 Process Description and Emission Sources ................................ ................................ .... 5 - 1 5.2.1 Process Description ................................ ................................ ................................ . 5 - 1 5.2.2 Emissions Data ................................ ................................ ................................ ........ 5 - 5 5.3 Available Controls and Regulatory Approaches ................................ ............................ 5 - 8 5.3.1 Available VOC Emission Control Options ................................ ............................. 5 - 8 5.3.2 Existing Federal, State and L ocal Regulations ................................ ..................... 5 - 23 5.4 RACT L evel of Control/Impacts ................................ ................................ .................. 5 - 24***E.O. 12866 Review

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vi 5.5 Factors to Consider in Developing Compliance Procedures ................................ ........ 5 - 25 5.5.1 Reciprocating Compressor Compliance Recommendations ................................ . 5 - 25 5.5.2 Centrifugal Compressor Equipped with a Wet Seal Recommendations .............. 5 - 26 5.5.3 Recommendations for Cover Design ................................ ................................ .... 5 - 27 5.5.4 Recommendations for Closed Vent Sy stems ................................ ........................ 5 - 27 6.0 PNEUMATI C CONTROLLERS ................................ ................................ ................................ ... 6 - 1 6.1 Applicability ................................ ................................ ................................ ................... 6 - 1 6.2 Process Description and Emission Sources ................................ ................................ .... 6 - 2 6.2.1 Process Description ................................ ................................ ................................ . 6 - 2 6.2.2 Emissions Data ................................ ................................ ................................ ........ 6 - 3 6.3 Available Controls and Regulatory Approaches ................................ ............................ 6 - 7 6.3.1 Available VOC Emission Control Options ................................ ............................. 6 - 7 6.3.2 Existing Federal, State and L ocal Regulations ................................ ..................... 6 - 19 6.4 Recommended RACT Level of Control/Impacts ................................ ......................... 6 - 20 6.4.1 Continuous Bleed Natural Gas - Driven Pneumatic Controllers L ocated at a Natural Gas Processing Plant ................................ ................................ ................................ .... 6 - 20 6.4.2 Continuous Bleed Natural Gas - Driven Pneumatic Controllers L ocated from the Wellhead to the Natural Gas Processing Plant or Point of Custody Transfer to an Oil Pipeline ................................ ................................ ................................ ........... 6 - 22 6.5 Factors to Consider in Developing Compliance Procedures ................................ ........ 6 - 24 6.5.1 ONG Production (Individual Continuous Bleed Pneumatic Controller with a Natural Gas Bleed Rate Greater than 6 scf Located from the Wellhead to the Natur al Gas Processing Plant or Point of Custody Transfer to an Oil Pipeline ) ....................... 6 - 24 6.5.2 Natural Gas Processing Segment (Individual Continuous Bleed Natural Gas - Driven Pneumatic Controller Lo cated at a Natural Gas Processing Plant) ....................... 6 - 25 7.0 PNEUMATI C PUMPS ................................ ................................ ................................ ................... 7 - 1 7.1 Applicability ................................ ................................ ................................ ................... 7 - 1 7.2 Process Description and Emission Sources ................................ ................................ .... 7 - 2 7.2.1 Process Description ................................ ................................ ................................ . 7 - 2 7.2.2 Emissions Data ................................ ................................ ................................ ........ 7 - 4 7.3 Available Controls and Regulatory Approaches ................................ ............................ 7 - 6 7.3.1 Available VOC Emission Control Options ................................ ............................. 7 - 6 7.3.2 Existing Federal, State and L ocal Regulations ................................ ..................... 7 - 16 7.4 Recommended RACT Level of Control ................................ ................................ ........... 7 - 17***E.O. 12866 Review

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vii 7.5 Factors to Consider in Developing Compliance Procedures ................................ ........ 7 - 19 7.5.1 ONG Production Segment Recommendations ................................ ...................... 7 - 19 7.5.2 Natural Gas Processing Segment Recommendations ................................ ........... 7 - 19 8.0 EQUIPMENT COMPONENT LEAKS FROM ONSHORE NATURAL GAS PROCESSI

NG PLANTS ................................ ................................ ................................ ................ 8 - 1 8.1 Applicability ................................ ................................ ................................ ................... 8 - 1 8.2 Process Description and Emission Sources ................................ ................................ .... 8 - 1 8.2.1 Process Description ................................ ................................ ................................ . 8 - 1 8.2.2 Equipment L eak Emission Data and Emissions Factors ................................ ......... 8 - 2 8.3 Available Controls and Regulatory Approaches ................................ ............................ 8 - 7 8.3.1 Available VOC Emission Control Options ................................ ............................. 8 - 7 8.3.2 Existing Federal, State and L ocal Regulations ................................ ..................... 8 - 13 8.4 Recommended RACT Level of Control for Equipment L eaks from Equipment Components at Natural Gas Processing Plants/Impacts ................................ ............... 8 - 13 8.5 Factors to Consider in Developing Equipment Component L eak Compliance Procedures

................................ ................................ ................................ ................................ ...... 8 - 15 9.0 FUGIT IVE EMISSIONS FROM WELL SITES AND GATHERING AND BOOSTING STATIONS ................................ ................................ ................................ ................................ ..... 9 - 1 9.1 Applicability ................................ ................................ ................................ ................... 9 - 1 9.2 Fugitive Emissions Description and Data ................................ ................................ ...... 9 - 1 9.2.1 Fugitive Emissions Description ................................ ................................ .............. 9 - 1 9.2.2. Emission Data and Emissions Factors ................................ ................................ .... 9 - 2 9.3 Available Controls and Regulatory Approaches ................................ .......................... 9 - 17 9.3.1 Available VOC Emission Control Options ................................ ........................... 9 - 17 9.3.2 Existing Federal, State and L ocal Regulations ................................ ..................... 9 - 30 9.4 Recommended RACT Level of Control/Impacts ................................ ......................... 9 - 31 9.5 Factors to Consider in Developing Fugitive Emissions RACT Procedures ................. 9 - 33 9.5.1 Monitoring Recommendations ................................ ................................ .............. 9 - 33 9.5.2 Repair Recommendations ................................ ................................ ..................... 9 - 35 APPENDIX***E.O. 12866 Review

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viii 

### L **IST OF TA BLES**  Table 3 - 1. Summary

of the ONG Source Category Emission Sources and Recommended RACT In cluded in this Guideline ................................ ................................ ................................ ............ 3 - 6 Table 4 - 1. Major Studies Reviewed for Consideration of Emissions and Activity Data a,b

......... 4 - 3 Table 4 - 2. Average Oil and Condensate Production and Storage Vessel Emissions per Production Rate Bracket ................................ ................................ ................................ ................................ . 4 - 5 Table 4 - 3. Total Capital Investment and Total Annual Costs of a Vapor Recovery Unit Sy stem 4 - 10 Table 4 - 4. Costs of Routing Emissions to and Existing Storage Vessel to a VRU ($/Ton of VOC Reduced) ................................ ................................ ................................ ................................ .... 4 - 11 Table 4 - 5. Total Capital Investment and Total Annual Costs of a Combustor .......................... 4 - 15 Table 4 - 6. Costs of Routing Emissions to and Existing Storage Vessel to a Combustion Device ($/ton of VOC Reduced) ................................ ................................ ................................ ............ 4 - 16 Table 4 - 7. Summary

of Storage Vessel Regulations from Nine States ................................ ..... 4 - 17 Table 5 - 1. Major Studies Reviewed for Emissions Data ................................ ............................. 5 - 5 Table 5 - 2. Methane Emission Factors for Reciprocating and Centrifugal Compressors ............ 5 - 7 Table 5 - 3. Baseline Methane VOC Emission Estimates for Reciprocating and Centrifugal Compressors ................................ ................................ ................................ ................................ . 5 - 8 Table 5 - 4. Estimated Annual Reciprocating Compressor Emission Reductions from Increa sing the Frequency

of Rod Packing Replacement ................................ ................................ ............. 5 - 12 Table 5 - 5. Cost of Control for Reciprocating Compressor Rod Packing Replacement ............ 5 - 13 Table 5 - 6. Cost of Reductions from Replacing a Wet Seal Centrifugal Compressor with a Dry Seal Centrifugal Compressor ................................ ................................ ................................ ..... 5 - 19 Table 5 - 7. Estimated Annual Centrifugal Compressor VOC Emission Reductions for Routing Wet Seal Fluid Degassing S ys tem to a Process , ................................ ................................ ........ 5 - 20 Table 5 - 8. VOC Cost of Control for Routing Wet Seal Fluid Degassing S ys tem to a Process . 5 - 20 Table 5 - 9. Estimated Annual VOC Emission Reductions for Routing Wet Seal Fluid Degassing Sy stem to a Combustion Device , ................................ ................................ ............................... 5 - 22 Table 5 - 10. Cost of Control for Routing Wet Seal Fluid Degassing Sy stem to a Combustion Device ................................ ................................ ................................ ................................ ........ 5 - 23***E.O. 12866 Review

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ix Table 6 - 1. Major Studies Reviewed for Consideration of Emissions and Activity Data ............ 6 - 4 Table 6 - 2. Average Emission Rates for High bleed and L ow bleed Pneumatic Controllers in the ONG Source Categorya ................................ ................................ ................................ ................ 6 - 7 Table 6 - 3. Cost Projections for Representative Pneumatic Controllers ................................ .... 6 - 10 Table 6 - 4. VOC Cost of Control for Replacing an Existing High Bleed Pneumatic Controller With a New L ow Bleed Pneumatic Controller ................................ ................................ .......... 6 - 10 Table 6 - 5. Compressor Power Requirements for Representative Instrument Air Sy stems a ...... 6 - 14 Table 6 - 6. Estimated Capital and Annual Costs of Representative Instrument Air Sy stems ($2012) ................................ ................................ ................................ ................................ ....... 6 - 17 Table 6 - 7. Cost of Control of Representative Instrument Air Sy stems in the Natural Gas Processing Segment ($2012) ................................ ................................ ................................ ...... 6 - 17 Table 7 - 1. Major Studies Reviewed for Consideration of Emissions and Activity Data ............ 7 - 5 Table 7 - 2. Average Bleed Emission Estimates per Pneumatic Device ................................ ....... 7 - 6 Table 7 - 3. Cost of Compressor Replacement for Existing Instrument Air S ystem ................... 7 - 12 Table 7 - 4. VOC Cost of Control for Routing Natural Gas - Driven Pump Emissions to an Existing Combustion Device ................................ ................................ ................................ .................... 7 - 13 Table 7 - 5. VOC Cost of Control for Routing Natural Gas - Driven Pump Emissions to a New Combustion Device ................................ ................................ ................................ .................... 7 - 14 Table 7 - 6. VOC Cost of Control for Routing Natural Gas - Driven Pump Emissions to an Existing VRU ................................ ................................ ................................ ................................ ........... 7 - 15 Table 7 - 7. VOC Cost of Control for Routing Natural Gas - Driven Pump Emissions to a New VRU ................................ ................................ ................................ ................................ ........... 7 - 16 Table 8 - 1. Major Studies Reviewed for Consideration of Emissions and Activity Data ............ 8 - 2 Table 8 - 2. Component Counts for Natural Gas Processing Model Plant ................................ .... 8 - 5 Table 8 - 3. Summary

of Equipment L eak Frequency for Natural Gas ................................ ......... 8 - 6 Table 8 - 4. Summary

of VOC Equipment L eak Emission Factors for the Natural Gas Processing Model Plant ................................ ................................ ................................ ................................ .. 8 - 6 Table 8 - 5. Summary

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

of the Gas Processing Component VOC Cost of Control ........................ 8 - 11***E.O. 12866 Review

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x Table 8 - 7. Summary

of the Natural Gas Processing Model Plant VOC Cost of Control for Optical Gas Imaging and Method 21 Monitoring ................................ ................................ ...... 8 - 13 Table 9 - 1. Major Studies Reviewed for Emissions and Activity Data ................................ ........ 9 - 3 Table 9 - 2. Estimated Average Number of Wells per Site of New Well Completion in 2012 ..... 9 - 6 Table 9 - 3. Estimated Average Number of Wells per Two Acre Site of New Well Completion and Recompletion in 2012, by HPDI Basin and Ty

pe of Well (Oil or Natural Gas, Hydraulically Fractured or Not) ................................ ................................ ................................ .......................... 9 - 7 Table 9 - 4. Average Component Count for Natural Gas Well Site Model Plant ........................ 9 - 11 Table 9 - 5. Average Component Count for Oil Well Site Model Plant ................................ ...... 9 - 12 Table 9 - 6. ONG Production Operations Average TOC Emissions Factors .............................. 9 - 13 Table 9 - 7. Estimated Fugitive VOC Emissions for Natural Gas Production Model Plant ........ 9 - 13 Table 9 - 8. Estimated Fugitive VOC Emissions for Oil Well Site Model Plant ........................ 9 - 13 Table 9 - 9. Average Component Count for the ONG Production Gathering and Boosting Station Model Plant ................................ ................................ ................................ ................................ 9 - 16 Table 9 - 10. Estimated Fugitive Methane and VOC Emissions for the ONG Production Gathering and Boosting Station Model Plant ................................ ................................ ............................. 9 - 17 Table 9 - 11. Summary

of the Model Plant VOC Cost of Control for the Annual OGI Monitoring Option ................................ ................................ ................................ ................................ ........ 9 - 21 Table 9 - 12. Summary

of the Model Plant VOC Cost of Control for the Semiannual OGI Monitoring Option ................................ ................................ ................................ ..................... 9 - 22 Table 9 - 13. Summary

of the Model Plant VOC Cost of Control for the Quarterly OGI Monitoring Option ................................ ................................ ................................ ..................... 9 - 23 Table 9 - 14. Summary

of the Model Plant VOC Cost of Control for the Annual Method 9 - 21 Monitoring Option ................................ ................................ ................................ ..................... 9 - 27 Table 9 - 15. Summary

of the Model Plant VOC Cost of Control for the Semiannual Method 9 - 21 Monitoring Option ................................ ................................ ................................ ..................... 9 - 28 Table 9 - 16. Summary

of the Model Plant VOC Cost of Control for the Quarterly Method 21 Monitoring Option ................................ ................................ ................................ ..................... 9 - 29***E.O. 12866 Review

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xi 

### LIST OF FIGURES Figure 3 - 1. ONG Sector Operations ................................ ................................ ............................ 3 - 4 Figure 4 - 1. Conventional Vapor Recovery S ys tem ................................ ................................ ..... 4 - 8 Figure 4 - 2. Schematic of a Ty pical Enclosed Combustion System ................................ ........... 4 - 13 Figure 4 - 3. Basic Schematic of a Thermal Oxidizer ................................ ................................ .. 4 - 14 Figure 5 - 1. Ty

pical Reciprocating Compressor Rod Packing S ys tem Diagram ......................... 5 - 2 Figure 5 - 2. Ty

pical Centrifugal Compressor Wet Seal ................................ ............................... 5 - 3 Figure 5 - 3. Ty

pical Centrifugal Compressor Tandem Dry Seal ................................ .................. 5 - 4 Figure 6 - 1. Natural Gas Pneumatic Control System ................................ ................................ .. 6 - 13 Figure 6 - 2. Compressed Instrument Air Control System ................................ .......................... 6 - 13***E.O. 12866 Review

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xii 

### ACRONYMS A **ND ABBREVIA TIONS**  **Acronyms/Abbreviations Description**  ACA Air Compliance Advisor ANGA America's Natural Gas Alliance APCD Air Pollution Control District API American Petroleum Institute AQMD Air Quality Management District ARCADI S a global consulting firm bbl/day barrels per day BMP best management practice BOE/day barrels of oil equivalent per day BSER best sy stem of emission reduction BTEX benzene, toluene, eth ylbenzene and xylenes Btu British thermal unit Btu/scf British thermal unit per standard cubic feet CAA Clean Air Act CAPP Canadian Association of Petroleum Producer’s CE indices Chemical Engineering's index CETAC - WEST Canadian Environmental Technology Advancement Corporation WEST C fm cubic foot per minute CFR Code of Federal Regulations CH4 Methane CLReport Carbon L imit Report CMSA Consolidated Metropolitan Statistical Area CO carbon monoxide CO$T - AIR a group of spreadsheet programs used t o cover 12 control devices and one category

of auxiliary equipment (ductwork) CO 2 carbon dioxide CTG control techniques guidelines E&P Tanks Program is a personal computer - based software designed to use site - specific information to predict emission from petroleum production storage tanks EIA Economic Impact Anal ys is ERG Eastern Research Group EVRU ejector vapor recovery units FIP Federal Implementation Plan FR Federal Register FRED Federal Reserve Economic Data***E.O. 12866 Review

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xiii **Acronyms/Abbreviations Description**  gal/yr gallon per year GDP gross domestic product GHG greenhouse gas Gr Gram GRI Gas Research Institute H 2 S hydrogen sulfide HAP hazardous air pollutants HFC H ydrofluorocarbon HON Hazardous Organic NESHAP HPDIdatabase provides production data and web - enabled anal ytical software tools for a wide range of oil and gas related customers IC F International a firm that provides professional ser vices and technology

solutions in strategy and policy

anal ysis, program management, project evaluation, and other services Inj/With injection/withdrawal components IR infrared kg/hr/comp kilogram per hour per component kg/hr/source kilogram per hour per source kg/MMBtu kilogram per million Btu kPa kilopascals kW Kilowatt lb/MMBtu pounds per million Btu LDAR leak detection and repair LLC liquid level controller Mcf million cubic feet MMcf/year million cubic feet per ye ar MSA Metropolitan Statistical Area Mscf/cyl thousand standard cubic feet per cylinder Mscf/y r/component thousand standard cubic feet per year per component NA Nonattainment Natural Gas STAR Program a voluntary partnership that encourages the adoption of CE technologies and practices NESHAP National Emission Standards for Hazardous Air Pollutants NGL natural gas liquids NOx nitrogen oxide NSPS New Source Performance Standards NSR New Source Review O&M operations & maintenance OAQPS Office of Air Quality Planning and Standards OCCM OAQPS Control Cost Manual***E.O. 12866 Review

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xiv **Acronyms/Abbreviations Description**  OEL open - ended lines OGI optical gas imaging ONG oil and natural gas OTR Ozone Transport Region OVA organic vapor anal yz er PC pressure controller PG&E Pacific Gas & Electric PM particulate matter PNAS Proceedings of the National Academy of Sciences ppm parts per million P pmv parts per million by volume PRD pressure relief devices PRV pressure relief valve PSD prevention of significant deterioration P si pounds per square inch P sig pounds per square inch gauge PTE potential to emit RACT reasonabl y available control technology S cf standard cubic feet scfh - cylinder standard cubic feet per hour - cylinder S cfm standard cubic feet per minute S cfh standard cubic feet per hour SIP State Implementation Plan SO 2 sulfur dioxide THC total hydrocarbons TOC total organic compounds Tpy tons per year TSD technical support document TVA toxic vapor analyzer U.S. United States U.S. EIA U.S. Energy Information Administration U.S. EPA U.S. Environmental Protection Agency VOC volatile organic compound VRU vapor recovery unit μg/m3 micrograms per cubic meter***E.O. 12866 Review

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1 - 1 Introduction 

### 1.0 **INTRODUCTION** Section 172(c)(1) of the Clean Air Act (CAA) provides that state implementation plans (SIPs) for nonattainment areas must include “reasonably available control measures” including “reasonabl y avai lable control technology” (RACT), for sources of emissions. CAA Section 182(b)(2)(A) stipulates that for M oderate (and higher) ozone nonattainment areas, states must revise their SIPs to include RACT for each category of volatile organic compound (VOC) sources covered b y control techniques guidelines (CTG) document issued between November 15, 1990 , and the date of attainment. CAA Section 184(b) requires that SIPs for states in ozone transport regions must comply with and implement RACT with respect to all sources of VOC in the state covered b y a CTG issued before or after November 15, 1990. CAA Section 184 (a) establishes a single ozone transport region comprised of the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jers ey , New York, Penns yl vania, Rhode Island, Vermont and the Consolidated Metropolitan Statistical Area (CMSA) that includes the District of Columbia. The U.S. Environmental Protection Agency (EPA) defines RACT as “the lowest emission limitation that a particular source is capable of meeting b y the application of control technology

that is reasonably

available considering technological and economic feasibility .” 44 FR 53761 (Sept ember 17, 1979). This guideline is intended to provide state , local and tribal air agencies (hereafter, air agencies) with information to assist them in determining RACT for VOCs from select oil and natural gas (ONG) source category emission sources. In developing this guideline , the EPA, among other things, evaluated the sources of VOC emissions from the ONG source category and the available control approaches for addressing these emissions, including the costs of such approaches. Based on available information and data, the EPA provides recommendations for RACT for select ONG so urce category emission sources for select sources in the ONG source category . Air agencies can use the recommendations in this guideline to inform their own determination as to what constitutes RACT for VOCs for the ONG source category sources presented in this document in their particular nonattainment areas. The information contained in this document is provided only as guidance. This guidance does not change, or substitute for,***E.O. 12866 Review

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1 - 2 Introduction requirements specified in applicable sections of the CAA or the EPA’s regulations; nor is it a regulation itself. This document does not impose any requirements on facilities in the ONG source category . It provides only recommendations for air agencies to consider in determining RACT. Air agencies are free to implement other techni call y- sound approaches that are consistent with the CAA and the EPA’s implementing regulations. The recommendations contained in this guideline are based on data and information currentl y available to the EPA. These general recommendations may not apply to a particular situation based upon the circumstances of a specific source. Regardless of whether an air agency chooses to implement the recommendations contained herein through their rules, or to issue rules that adopt different approaches for RACT for VOC s from ONG source category sources, air agencies must submit their RACT rules to the EPA for review and approval as part of the SIP process. The EPA will evaluate the rules and determine, through notice and comment rulemaking in the SIP review process, whe ther the submitted rules meet the RACT requirements of the CAA and the EPA’s regulations. To the extent an air agency adopts any of the recommendations in this guidance into its RACT rules, interested parties can raise questions and objections about the substance of this guidance and the appropriateness of the application of this guidance to a particular situation during the development of the se rules and the EPA’s SIP review process. Section 182(b)(2) of the CAA requires that a CTG issued between November 15, 1990, and the date of attainment include the date b y which states subject to CAA section 182(b) must submit SIP revisions in response to the CTG. Pursuant to CAA section 182(b)(2) , states required to submit rules consistent with CAA section 182(b) must submit their SIP revisions to include RACT requirements for sources covered b y this guideline within the period set forth b y the Administrator in issuing the relevant CTG .***E.O. 12866 Review

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2 - 1 Background and Overview 

### 2.0 **BA CKGROUND AND OVERVIEW**  There have been several federal and state actions under the CAA to reduce VOC emissions from certain segments of the ONG source category . The statutory support and summary of these actions is provided in this chapter . 

### 2.1 **New Sour**  **ce Performance Standards** Section 111 of the CAA requires the EPA Administrator to list categories of stationary sources, if such sources “...cause(s) or contribute(s) significantly to air pollution which may reasonabl y be anticipated to endanger public health or welfare. ” The EPA must then issue performance standards for such source categories. A performance standard reflects the degree of emission limitation achievable through the application of the best sy stem of emission reduction (BSER) that the EPA deter mines has been adequately demonstrated. The EPA may consider certain costs and non - air quality health and environmental impact s and energy requirements when establishing performance standards . These standards are referred to as new source performance stand ards (NSPS). The EPA has the authority to define the source categories, determine the pollutants for which standards should be developed, identify the facilities within each source category

to be covered and set the emission level of the standards. **2.1.1 Statutory**  **Au thority**  In setting or revising a performance standard, CAA section 111(a)(1) provides that performance standards are to “reflect the degree of emission limitation achievable through the application of the best s ystem of emission reduction which (taking into account the cost of achieving such reduction and any non - air quality health and environmental impact and energy requirements) the Administrator determines has been adequatel y demonstrated.” As noted previously , this level of control is referred to as the BSER. In determining the BSER, a technology

review is conducted that identifies what emission reduction sy stems exist and how much the identified s ys tems reduce air pollution in practice. For each control sy stem identified, the costs and secon dary

air benefits (or dis - benefits) resulting from energy requirements and non - air quality impacts , such as solid waste generation , are also evaluated. This analy sis determines the BSER. The resultant standard is usu ally a numerical emission limit expresse d as a performance level (i.e., a rate - bas ed standard or percent control) that reflects the BSER.***E.O. 12866 Review

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2 - 2 Background and Overview Although such standards are based on the BSER, the EPA may not prescribe a particular technology

that must be used to comply with a performance standard, except in instances where the Administrator determines it is not feasible to prescribe or enforce a standard of performance. Ty pically , sources remain free to elect whatever control measures that they choose to meet the emission limits. Upon promulgation, an NSPS becomes a national standard to which all new, modified or reconstruct ed sources must comply . CAA section 111(b)(1)(B) requires the EPA to “at least every 8 years review and, if appropriate, revise” performance standards unless the “Administrator determines that such review is not appropriate in light of readily available in formation 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 currentl y regu lated for that source categ ory . **2.1.2 ONG**  **Source Category NSPS Regulatory**  **History** In 1979, the EPA listed crude ONG production on its priority list of source categories for promulgation of NSPS (44 FR 49222, August 21, 1979). Since the 1979 listing, the EPA has promulgated performan ce standards to regulate sulfur dioxide (SO 2 ) emissions from natural gas processing and VOC emissions from the production, processing, transmission and storage segments of the ONG industry . On June 24, 1985 (50 FR 26122), the EPA promulgated an NSPS for th e source category

that addressed VOC emissions from leaking components at onshore natural gas processing plants (40 CFR part 60, subpart KKK). On October 1, 1985 (50 FR 40158), a second NSPS was promulgated for the source category that regulates SO 2 emissi ons from natural gas processing plants (40 CFR part 60, subpart LLL). Other than natural gas processing plants, the EPA had not previousl y set NSPS for any other ONG operations. On August 16, 2012 (77 FR 49490), the EPA finalized its review of NSPS standards for the listed ONG source category

and revised the NSPS for VOC from leaking components at onshore natural gas processing plants and the NSPS for SO 2 emissions from natural gas processing plants. The EPA also established standards for certain oil and ga s operations not covered b y the existing standards. In addition to the operations that were covered previously, the EPA established new standards to regulate VOC emissions from hydraulicall y fractured gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels.***E.O. 12866 Review

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2 - 3 Background and Overview In 2013 (78 FR 58416) and 2014 (79 FR 79018), the EPA amended the standards set in 2012 in order to improve implementation of the standards. In 2015, the EPA proposed new standards to regulate methane and VOC emissions across the ONG source category . Specificall y, we proposed both methane and VOC standards for several emission sources not currentl y covered by the NSPS (i.e., hydraulically fractured oil well completions, fugitive emissions from well sites an d compressor stations, pneumatic pumps). In addition, we proposed methane standards for certain emission sources that are currentl y regulated for onl y VOC (i.e., h ydraulicall y fractured gas well completions, equipment leaks at natural gas processing plants ). With respect to certain equipment that are used across the source category, the current NSPS regulates only a subset of these equipment (pneumatic controllers, centrifugal compressors, reciprocating compressors). The proposed amendents would establish m ethane standards for these equipment across the source category

and extend the current VOC standards to the remaining unregulated equipment. Several of the technical support documents (TSDs) prepared in support of the final and proposed NSPS actions for the ONG source category include data and analy ses considered in developing recommendations in this guideline , to the extent that the data and anal ys es are also relevant to control options for existing sources and are referred to throughout this guidance document: 1) The TSD for the 2011 NSPS pro posal, published in July , 2011, will be referred to in this document as the "2011 NSPS TSD". 1 2) The supplemental TSD for the 2012 final NSPS standards, published April, 2012, will be referred to in this document as the "2012 NSPS TSD" or ”2012 NSPS STSD 2 3) The TSD for the 2015 proposed NSPS standards is referred to in this document as the “2015 NSPS TSD”. 3 Additio nally , e missions information and counts for various emission sources were summarized from facility - level data submitted to the Greenhouse Gas Reporting Program

1 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. 2 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New Source Performance Standards . April 2012. Docket ID No. EPA - HQ - OAR - 2010 - 0505 - 4550. 3 U.S. Environmental Protection Agency. Oil and Natural Gas Source Category: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Technical Support Document for the Proposed Amendments to the New Source Performance Standards. June 2015.***E.O. 12866 Review

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2 - 4 Background and Overview (GHGRP) 4 and data used to calculate national emissions in the Inventory of U.S. Greenhouse Gas Emissions and Sinks. 5 The most recent published data was from 2013 and was used for various portions of the analy sis. For the purposes of this document these data sources are referred to as "GHGRP" and “GHG Inventory”. 

### 2.2 **CTG** In December 1983, the EPA pub lished a CTG for controlling VOC emissions from equipment leaks from natural gas/gasoline processing plants (1983 CTG). 6 As di scussed in section 2.1 of this c hapter, the 2012 NSPS established VOC performance standards for new and modified sources. This gui deline addresses existing sources of VOC emissions and provides recommendations for RACT for the ONG source category . Most of the ONG source category source VOC emissions estimates presented in this document are based on methane emissions because many of our emission factors are for methane. We then calculated VOC emissions using ratios of methane to VOC in the gas for the different segments of the industry . These ratios , and the procedures used to calculate them , are documented in a memor andum characterizing gas composition developed during the NSPS process. 7 Herein, we refer to this memorandum as the "2011 Gas Composition Memorandum". Because methane emissions are the basis for most of our VOC emissions estimates, in several instances wh ere we provide VOC emissions per source/model plant, we also provide the methane emissions that are the basis for our VOC emissions estimates. 

### 2.3 **State and Local Regulations** In addition to the requirements that apply based on the NSPS and the existing CTG recommended RACT level of control for equipment component leaks (40 CFR part 60 , subpart OOOO (equivalent to 40 CFR part 60, subpart VVa for sources constructed or modified after August 23, 2011 and 40 CFR part 60 , s ubpart VV/KKK for sources constructed o r modified on

4 U.S. Environment al Protection Agency. Mandatory Reporting of Greenhouse Gases from Petroleum and Natural Gas Systems

– Subpart W . Washington, DC. November 2010. 5 U.S. EPA. Inventory of U.S. Greenhouse Gas Inventory and Sinks. 1990 - 2012. Available at http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/archive.html 6 U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC, 27711. Guideline Series. Control of Volatile Organic Compound Eq uipment Leaks from Natural Gas/Gasoline Processing Plants. December 1983. EPA - 4 50/3 - 83 - 007 7 Memorandum to Bruce Moore, U.S. EPA from Heather Brown, EC/R. Composition of Natural Gas for use in the Oil and Natural gas Sector Rulemaking . July 2011. Docket ID No. EPA - HQ - OAR - 2010 - 0505 - 0084.***E.O. 12866 Review

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2 - 5 Background and Overview or before August 23, 2011 ) ) , some states have adopted regulations that regulate VOC emissions from existing sources (constructed or modified prior to proposal of the 2012 NSPS) 8 other than leaks from equipment components in the ONG source cat egory . S everal states regulate VOC emissions from storage vessels in the ONG source category , where the format of the state requirements are similar but the stringency based on applicability

thresholds differ . For example , most states that require control of VOC emissions reductions in ozone nonattainment areas from existing storage vessels (except Wyoming) require that VOC emissions be reduced b y 95 percent , but have differing applicability criteria . In addition to equipment component leaks and storage ve ssel VOC emissions, there are also a few states (e.g., Colorado, Wyoming, Montana) that have established specific permitting requirements or regulations that control VOC emissions from other ONG source category emission sources (e.g., compressors, pneumati cs, fugitive emission components): 1) The Colorado Department of Public Health and Environment, Air Quality Control Commission has developed emission regulations 3, 6 and 7 that appl y to ONG source category emission sources in Colorado. (https://www.colorado.gov/pacific/cdphe/summary- oil - and - gas - emissions - requirements ) 2) Montana requires oil or gas well facilities to control emissions from the time the well is compl eted until the source is registered or permitted (Registration of Air Contaminant Sources Rule, Rule 17.8.1711, Oil or Gas Well Facilities Emission Control Requirements). (http://www.mtrules.org/gateway /ruleno.asp?RN=17%2E8%2E1711 . ) 3) The Wyoming Department of Environmental Quality limits VOC emissions from existing sources in ozone nonattainment areas and has issued specific permitting guidance for statewide and ozone nonattainment areas that apply to ONG production facilities (Chapter 6, Section 2 Permitting Guidance, last revised in September 2013). (http://www.oilandgasbmps.ort/laws/wyoming_law.php . ) In some states, general permits have been developed for ONG source category facilities. General permits are permits where all the terms and conditions of the permit are developed for a given source category

and authorize the construction, modification, and/or operation of facilities that meet the terms and conditions. For example, West Virginia, Ohio and Pennsylvania have developed General Air Permits. The Pennsylvania Department of Environmental Protection has

8 77 FR 49490; August 16, 2012***E.O. 12866 Review

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2 - 6 Background and Overview issued a General Permit, General Plan Approval and Permit Exemption 38 for natural gas dispensing facilities and oil and gas exploration, development and production operations. Pennsylvania also applies conditions on flaring of emissions. Under the Permit 38 exemptions, there are criteria set out for the oil and gas source category that include unconditionally exempt and conditionally

exempt criteria. Unconditionally exempt operations/equipment include conventional wells, conventional wellheads and associated equipment , well - drilling, completion and work - over activiti es, and non - road engines. Unconventional wells, wellheads and associated equipment (including equipment components, storage vessels) are conditionally exempt. Conditions include compliance with 40 CFR part 60 , s ubpart OOOO and Pennsylvania’s General P ermit 5 (GP - 5) and a demonstration that the combined VOC emissions from all sources at a facility < 2.7 tons per ye ar (tpy) on a 12 - month rolling basis. For ONG source category facilities that do not meet these conditions, a case - by- case plan approval is required. 9 There may also be local permit requirements for control of VOC emissions from existing sources of VOC emissions in the ONG industry , such as those required by the Bay Area Air Quality Management District (BAAQMD) for pneumatic controllers. The BAAQMD require s that a permit to operate applicant provide the number of high bleed and low bleed pneumatic dev ices in their permit application. F acilities that use high bleed devices might be required to provide device - specific bleed rates and supporting documentation for each high bleed device. In cases where emissions are high from high bleed devices, BAAQMD might require that the facility conduct fugitive monitoring and/or control requirements under conditions of their permit to operate 10 on a case - by- ca se basis. Similar to the permitting and VOC emissions reduction requirement that have been specificall y tailored for the ONG source category in several states, VOC emissions restrictions may still apply

to some existing ONG facilities in other states . S tat es may have registration and permitting restrictions on VOC emissions that may appl y to an emissions source as a resu lt of an operating, new source review (NSR) nonattainment or prevention of significant deterioration (PSD) permitting (e.g., on a case - by- case basis) based on air quality maintenance or improvement goals of an area. Such air p ermi ts specify operating conditions and emissi on limits . 9 Pennsylvania Department of Environmental Protection. Comparison of Air Emission Standards for the Oil & Natural Gas Industry (Well Pad Operations, Natural Gas Compressor Stations, an d Natural Gas Processing Facilities). May 23, 2014. 10 Cheng, Jimmy. Permit Handbook. Chapter 3.5 Natural Gas Facilities and Crude Oil Facilities. Bay Area Air Quality Management District. September 16, 2013.***E.O. 12866 Review

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2 - 7 Background and Overview To en sure that sources follow the permit requirements, air permits also contain monitoring, recordkeeping, and reporting requirements. We considered these existing state and local requirements regulating VOC emissions from the ONG source category in preparing this guideline. 

### 2.4 **Development of this G**  **uideline** We developed and based our RACT contained i n this document af ter reviewing the 1983 CTG, 2012 NSPS , 2013 NSPS, existing state and local VOC emission reduction approaches (where a specific regulation exists that regulates an emissions source evaluated under this guideline), and information on costs, emissions and available VOC emission control technologies . For instance, on April 15, 2014, the EPA released for external peer review five technical white papers on potentially significant sources of emi ssions in the ONG source category . The white papers focused on technical issues covering emissions and mitigation techniques th at target methane and VOCs. We refer to information included in the white papers, along with the input we receive d from the peer reviewers and the public, when evaluating and recomm ending a RACT level of control for emission sources in the ONG source category . We have divided the remainder of this document into seven c hapters . Chapter three describes the ONG production source category . C hapters four through nine describe ONG emission sources (i.e., storage vessels, compressors, pneumatic controllers, pneumatic pumps, equipment component leaks from natural gas processing plants and fugitive emissions from well sites and compressor stations), available control and regulatory approaches (including existing federal, state and local requirements ) and our RACT recommendations. The appendix provides example model rule sections by emissions source that can be used by states if they

choose to adopt the recommended RACT level of control presente d in this document.***E.O. 12866 Review

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3 - 1 Overview of the ONG Source Category and Sources 

### 3. **0 OVERVIEW OF THE**  **ONG SOURCE CA** **TEGORY A ND SOURCES**  **SELECTED FOR RACT RECOMMENDA TIONS**  The ONG source category includes operations involved in the extraction and production of ONG , as well as the processing, transmission and distribution of natural gas. Section 3.1 presents an overall description of the ONG source category and Section 3.2 presents the VOC emission sources for which we are recommending RACT withi n the ONG source category . 

### 3.1 **Overview of the**  **ONG Sector**  The ONG sector includes operations involved in the extraction and production of crude ONG , as well as the processing, transmission and distribution o f natural gas. For oil, the sector includes all operations from the well to the point of custody transfer at a petroleum refin ery. For natural gas, the sector includes all operations from the well to the customer. The ONG operations can generall y be separated into four segments: (1) ONG production, (2) natural gas processing, (3) natural gas transmission and storage and (4) natural gas distribution. We briefl y discuss e ach of these segments below. ONG production includes onshore o perations. Production operations include the wells and all related processes used in the extraction, production, recove ry , lifting, stabilization and separation or treating of oil and/or natural gas (including condensate). Production components may include, but are not limited to, wells and related casing head, tubing head and “Christmas tree” piping, as well as pumps, compressors, heater treaters, separators, storage vessels, pneumatic devices and dehydrators. Production operations also include well drilling, completion and recompl etion processes , which include all the porta ble non - self

- propelled apparati associated with those operations. Production sites include the “pads” where the wells are located and stand alone sites where oil, condensate, produced water and natural gas from several wells may be separated, stored an d treated. The production segment also includes the low pressure, small diameter, gathering pipelines and related components that collect and transport the oil, natural gas and other materials and wastes from the we lls to the refineries or natural gas processing plants. These are also referred to as “flow lines” and “sales lines.”***E.O. 12866 Review

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3 - 2 Overview of the ONG Source Category and Sources There are three basic ty

pes of wells: Oil wells, natural gas wells and associated natural gas wells. Oil wells can have “associated” natural gas that is separated and processed or the crude oil can be the onl y product processed. Once the crude oil is separated from water and other impurities, it is essentially ready to be transported to the refinery via truck, railcar or p ipeline. The petrol eum refining sector is considered separately fro m the ONG sector . Therefore, at the point of custody

transfer at the refinery , the oil l eaves the ONG source sector and ente rs the petroleum refining sector. Natural gas is primaril y made up of methane . Howev er, whether natural gas is associated natural gas from oil wells , or non - associated natural gas from natural gas or condensate wells, it commonly

exists in mixtures with other hydrocarbons. These h ydrocarbons are often referred to as natural gas liquids (N GL). They are sold separately

and have a variety of 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 certain hydrocarbon s and fluids from the natural gas to produce “pipeline quality” dry natural gas. While some of the processing can be accomplished in the production segment, the complete processing of natural gas takes place in the natural gas processing segment. Natural g as 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: o il and condensate separation, water removal, separation of natural gas liquids, sulfur and CO 2 removal, fractionation of NGL and other processes, such as the capture of CO 2 separated from natural gas streams for delivery outside the facility . The pipeline quality

natural gas leaves the processing segment and ent ers the transmission and storage segment. Pipelines in the natural gas transmission and storage segment can be interstat e pipelines that carry natural gas across state boundaries or intrastate pipelines that transport the gas within a single state. While interstate pipelines may be of a larger diameter and operated at a higher pressure, the basic components are the same. To ensure that the natural gas flowing through any pipeline remains pressurized, compress ion of the gas is required periodicall y along the pipeline. This is accomplished by compressor stations usually placed at intervals between 40 and 100 mile s along the pipeline. At a compressor station, the natural gas***E.O. 12866 Review

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3 - 3 Overview of the ONG Source Category and Sources enters the station, where it is compre ssed by reciprocating or centrifugal compressors. Compressors are mechanical devices that increase the pressure of natural gas and allow the natural gas to be transported from the production site, through the suppl y chain, and to the consumer. In the produ ction segment, compressors are used at the wellhead to compress gas for fluids removal and pressure equalization with gathering equipment s ys tems. However, the primary use of compressors is in the natural gas processing, transmission and storage (particularl y underground storage) segments of the industry. In addition to the pipelines and compressor stations, the natural gas transmission and storage segment includes aboveground and underground storage facilities. Underground natural gas storage includes subs urface storage, which typ ically consists of depleted natural gas or oil reservoirs and salt dome caverns used for storing natural gas. One purpose of this storage is for load balancing (equalizing the receipt and delivery of natural gas). At an underground storage site, there are typicall y other processes, including compression, dehydration and flow measurement. The distribution segment is the final step in delivering natural gas to customers. The natural gas enters the distribution segment from delivery po ints located on interstate and intrastate transmission pipelines to business and household customers. Natural gas distribution sy stems consist of thousands of miles of piping, including mains and service pipelines to the customers. Distribution sy stems som etimes have compressor stations, although they are considerabl y smaller than transmission compressor stations. Distribution systems include metering stations, which allow distribution companies to monitor the natural gas in the sy stem. Essentiall y, these m etering stations measure the flow of natural gas and allow distribution companies to track natural gas as it flows through the s ys tem. Figure 3 - 1 presents a schematic of ONG operations.

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3 - 4 Overview of the ONG Source Category and Sources **Figure 3 -**  **1 .**  **ONG Sector**  **Operations*****E.O. 12866 Review

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3 - 5 Overview of the ONG Source Category and Sources Emissions can occur from a variety of processes and points throughout the ONG source category . Primaril y, these emissions are organic compounds such as methane , ethane, VOC and organic hazardous air pollutants ( HAP ) . The most common organic HAP are n - hexane and benzene, to luene, eth ylbenzene and xylenes (BTEX). H 2 S and SO 2 are emitted from production and processing operations that handle and treat sour gas. 11 In addition, there are significant emissions associated with the reciprocating internal combustion engines and combustion turbines that power compressors throughout the ONG source category . However, emissions from internal combustion engines and combustion turbines are covered b y regulations specific to engines and turbines and, thus, are not addressed in this action. 

### 3. **2 Sources Selected For RA** **CT Recommend ations**  This CTG covers select VOC emission sources in the ONG source category . A s noted in Section 2 of this document, the VOC RACT recommendations contained in this document were made based on the review of the 1983 CTG, the 2012 NSPS (77 FR 49490, Augus t 16, 2012), 2013 NSPS (78 FR 58416, September 23, 2013) , 2014 NSPS amendments (79 FR 79018, December 31, 2014), the 2015 NSPS proposal, existing state and local VOC emission reduction approaches (where a specific regulation exists that regulates an emiss ions source evaluated under this guideline), and information on costs, emissions and available VOC emission control technologies obtained since issuance of these NSPS . For instance, as mentioned in S ection 2.4, the EPA released for external peer review five technical white papers on potentially significant sources of emissions in the oil and gas source category . We refer to information included in the white papers, along with the input we receive d from the peer reviewers and the public, when evaluating and recommending a RACT level of control for emission sources in the ONG source category . In considering costs, we compared control options and estimated costs and emission impacts of multiple, specific work practice and/or emission stand ard options under c onsideration. Recommendations are presented here for the subset of existing sources in the ONG source category where the application of controls is judged reasonable, given the availability of

11 Sour gas is defined as natural gas with a maximum H 2 S content of 0.25 grams ( gr) /100 standard cubic feet ( scf ) (4 parts per million by volume (ppmv) ) along with the presence of CO 2 .***E.O. 12866 Review

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3 - 6 Overview of the ONG Source Category and Sources demonstrated control technologies, emission reductions that can be achieved and the cost of control. For RACT, we have not evaluated sources that are not regulated by the ONG NSPS that regulate VOC emissions (proposed or promulgated). A dditionally , we have not evaluated sources that emit predominantly

methan e and not VOC emissions for VOC RACT . For example, we are not recommending RACT for sources in the transmission and storage segment because the VOC content in the pipeline quality natural gas is extremely

low in this segment. For similar reasons , we are not recommending RACT f or sources in the distribution segment . Also, w e have not included RACT recommendations for hydraulically fractured ONG wells because when we established VOC standards for natural gas well completions under the 2012 NSPS and p roposed standards for oil well completions in the 2015 NSPS proposal, we established/proposed VOC standards for completions following h ydraulic refracturing (which would cover existing sources). Specificall y, the 2012 NSPS and 2015 NSPS proposal considers completions following hydraulic refracturing to potentially be a modification triggering the NSPS requirements. Lastl y, the guidelines do not cover VOC emissions from internal combustion engines and combustion turbines (which are covered by regulations spe cific to engines and turbines). Table 3 - 1 presents a s umm ary of the ONG emission sources and recommended RACT i ncluded in this guideline . **Table 3 -**  **1 . Summary o**  **f the ONG**  **Source Category Emission Sources and Recommended**  **RACT Included in this G**  **uideline Emission Source**  **Applicability RACT Requirements**  Storage Vessels Individual storage vessel . 95 percent reduction of VOC emissions from storage vessels with a potential to emit (PTE) greater than 6 tpy . Pneumatic Controllers Individual continuous bleed , natural gas - driven pneumatic controller located at a natural gas processing plant . Must have a natural g as bleed rate of zero scfh (unless there are functional needs, including but not limited to response time, safety and positive actuation, requi ring a bleed rate greater than zero scfh).***E.O. 12866 Review

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3 - 7 Overview of the ONG Source Category and Sources **Emission Source Applicability**  **RACT Requirements**

Individual continuous bleed natural gas - driven pneumatic controller located from the wellhead to the natural gas processing plant or point of custody transfer to an oil pipeline . Must have a natural gas bleed rate less than or equal to 6 scfh (unless there are functional needs, including but not limited to response time, safety and positive actuation, requiring a bleed rate greater than 6 scfh). Pneumatic Pumps Individual natural gas - driven chemical/methanol and diaphragm pump located at a natural gas processing plant . Must have zero natu ral gas emissions.

Individual natural gas - driven chemical/methanol an d diaphragm pump located from the well site to the point of custody transfer to the natural gas transmission and storage segment. I f there is an existing control device at the location of the pneumatic pump, reduce VOC emissions from each gas driven chemical/methanol and diaphragm pump at the location by 95 percent or greater. Compressors (Centrifugal and Reciprocating) Individual reciprocating compressor located between the wellhead and point of custody transfer to the natural gas transmission and storage segment. Reduce VOC emissions by replacing reciprocat ing compressor rod packing after 26,000 hours of operation or 36 months since the most recent rod packing replacement. Alternatively, route rod packing emissions to a process through a closed vent system under negative pressure. Individual reciprocating compressor located at a well site, or an adjacent well site and servicing more than one well site RACT would not apply.

Individual centrifugal compressor using wet seals that is located between the wellhead and point of custody transfer to the natural gas transmission an d storage segment. Reduce VOC emissions from each centrifugal compressor wet seal fluid gassing system by 95 percent or greater. Individual centrifugal compressor using wet seals located at a well site, or an adjacent well site and servicing more than one well site. RACT would not apply.***E.O. 12866 Review

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3 - 8 Overview of the ONG Source Category and Sources **Emission Source Applicability**  **RACT Requirements**

Individual centrifugal compressor equipped with a dry seal. RACT would not apply. Equipment Component Leaks Equipment components in VOC service located at a natural gas processing plant . Implement the 40 CFR part 60, subpart VVa leak detection and repair ( LDAR) program for natural gas processing plants constructed or modified on or before August 23, 2011. Fugitive Emissions Individual well site. Implement an optical gas imaging ( OGI) monitoring and repair program which includes semiannual monitoring of fugitiv e emissi on components using OGI. Individual compressor station located from the wellhead to the point of custody transfer to the natural gas transmission and storage segment or point of custody transfer or to an oil pipeline . Implement an OGI monitoring and repair program that includes semiannual monitoring of fugitiv e emission components using OGI.***E.O. 12866 Review

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4 - 1 Storage Vessels 

### 4.0 **STORA GE VESSELS**  St orage vessels are sources of VOC emissions in the ONG source category . This chapter provides a description of the ty pes of storage vessels p resent in the oil and gas source category , and provides VOC emission estimates for a typical uncontrolled storage vessel. This chapter also presents control techniques used to reduce VOC emissions from storage v essels , along with costs and emi ssion reductions . Finally , this chapter provides a discussion of our recommended RACT for storage vessels. 

### 4.1 **Ap plicability**  For purposes of this guideline , the emissions and emission controls discussed herein would apply

to a tank or other vessel in the ONG source category that contains an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water, and that is constructed primarily

of non - earthen materials (such as wood, concrete, steel, fibergla ss, or plastic) that provide structural support. The emissions and emission controls discussed herein would not apply

to the following vessels: 1) Vessels that are skid - mounted or permanently attached to something that is mobile (such as trucks, railcars, barges or ships), and are intended to be located at a site for less than 180 consecutive day s. 2) Process vessels such as surge control vessels, bottoms receivers or knockout vessels. 3) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere. 

### 4.2 **Process Description and Emission Sources**  **4.2 .1**  **Process Description** Storage vessels in the ONG source category are used to hold a variety of liquids, including crude oil, condensates, produced water, etc. Underground c rude oil contains many lighter h ydrocarbons in solution. When the oil is brought to the surface and processed, many of the dissolved lighter h ydrocarbons (as well as water) are removed through a series of high pressure and low - pressure separators. Crude oi l under high pressure conditions is passed through either a two - phase separator (where the associated gas is removed and any oil and water remain***E.O. 12866 Review

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4 - 2 Storage Vessels together) or a three - phase separator (where the associated gas is removed and the oil and water are also separ ated). At the separator, low pressure gas is phys ically separated from the high pressure oil. The remaining low pressure oil is then directed to a storage vessel where it is stored for a period of time before being transported off - site. Much of the remaini ng h ydrocarbon gases in the oil are released from the oil as vapors in the storage vessels. Storage vessels are typically installed with similar or identical vessels in a group, referred to in the industry as a tank battery . Emissions of the hydrocarbons f rom storage vessels are a function of working, breathing (or standing), and flash losses. Working losses occur when vapors are displaced due to the emptying and filling of storage vessels. Breathing losses are the release of gas associated with temperature fluctuations and other equilibrium effects. Flash losses occur when a liquid with entrained gases is transferred from a vessel with higher pressure to a vessel with lower pressure, thus allowing entrained gases or a portion of the liquid to vaporize or fl ash. In the ONG production source category , flashing losses occur when crude oils or condensates flow into a storage vessel from a processing vessel operated at a higher pressure. Ty pically , the larger the pressure drop, the more flash emissions will occur in the storage vessel . Temperature of the liquid may

also influence the amount of flash emissions. The volume of gas vapor emitted from a storage vessel depends on many factors. Lighter crude oils flash more hydrocarbons than heavier crude oils. In storag e vessels where the oil is frequently cycled and the overall throughput is high, working losses are higher. Additionally , the operating temperature and pressure of oil in the separator dumping into the storage vessel will affect the volume of flashed gases coming out of the oil. The composition of the vapors from storage vessels varies, and the largest component is methane, but also may include ethane, butane, propane, and HAP such as BTEX , and n - hexane. **4.2.2 Emissions Data**  **4.2.2.1 Summary of Major Studies**  **and Emissions** Given the potentially

significant emissions from storage vessels, there are numerous studies and reports available that estimate storage vessel emissions. We consulted several of these studies and reports to evaluate the emissions and emissi on reduction options for storage vessels. Table 4 - 1 pre sents a summary of the references for these reports , along with an indication of the ty

pe of inf ormation available in each reference .***E.O. 12866 Review

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4 - 3 Storage Vessels **Table 4 -**  **1 . Major Studies Reviewed for Co**  **nsideration of Emissions and Activity Data a,b**  **Report Name Affiliation**  **Year of Report**  **Activity**

**Factors Emission**  **s**

**Data Control** 

**Options** VOC Emissions from Oil and Condensate Storage Tanks Texas Environmental Research Consortium 2009 Regional X X Upstream Oil and Gas Storage Tank Project Flash Emissions Models Evaluation

– Final Report Texas Commission on Environmental Quality 2009 Regional X Initial Economics Impact Analysis for Proposed State Implementation Plan Revisions to the Air Quality Control Commission’s Regulation Number 7 Colorado Air Quality Control Commission 2008 NA X

E&P TANKS API National X Inventory of U.S. Greenhouse Gas Emissions and Sinks EPA Annual National X Greenhouse Gas Reporting Program (Annual Reporting: Current Data Available for 2011 - 2013) C EPA 2014 Facility Level X X NA = Not Applicable a. U.S. Environmental Protection Agency. ONG Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New Source Performance Standards . April 2012. EPA Docket ID No. EP A - HQ - OAR - 2010 - 0505 - 4550. b. U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Technical Support . July 2011. EPA - 453/R - 11 - 002. c U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: Background Technical Support Document . Climate Change Division. Washington, DC. November 2014. **4.2.2.2 Representative Storage Vessel**  **Baseline Emissions**  Storage vessels vary

in size and throughputs. Average storage vessel emission s , in terms of mass of emissions per throu ghput, were developed for both crude oil and condensate storage vessels . We also developed m ass emissions per throughput estimates using the American Petroleum Institute’s (API’s) E&P Tanks program and more than 100 storage vessels across the country with varying characteristics. 12 The VOC emissions per throughput estimates used for this anal ys is are:

12 American Petroleum Institute. Production Tank Emissions Model . E& P Tank Version 2.0. A Program for Estimating Emissions from Hydrocarbon Production Tanks . Software Number 4697. April 2000.***E.O. 12866 Review

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4 - 4 Storage Vessels 1) Uncontrolled VOC Emissions from Crude Oil Storage Vessels = 0.214 tp y VOC/barrel per day (bbl/day); and 2) Uncontrolled VOC Emissions from Condensate Storage Vessels = 2.09 tp y VOC/bbl/day . On a nationwide basis, there are a wide variety of storage vessel sizes, as well as rates of throughput for each tank. Emissions are directl y related to the throughput of liquids for a given storage vessel; therefore, in support of the 2013 NSPS Reconsideratio n final rule, we adopted production rate brackets developed b y the U.S. Energy Information Administration (EIA) for our emission estimates. To estimate the emissions from an average storage vessel within each production rate bracket, we developed average p roduction rates for each bracket. This average was calculated using the EIA published nationwide production per well per day for each production rate bracket from 2006 through 2009. Table 4 - 2 presents the average oil production and condensate production in barrels per well per day. For this analysis, we considered the liquid produced (as reported b y the EIA) from oil wells to be crude oil and f rom gas wells to be condensate. Table 4 - 2 presents the av erage VOC emissions for each storage vessel within each production rate bracket were calculated b y appl ying the average production rate (bbl/day) to the VOC emission s per throughput estimates (tp y VOC/bbl/day) .***E.O. 12866 Review

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4 - 5 Storage Vessels **Table 4 -**  **2 . Average Oil and Condensate Production and**  **Storage Vessel Emissio**  **ns per Production Rate Bracket** 

**P rodu**  **c tion**  **Ra te Bracket**  **(B O**  **E /d**  **a y** **) a**  **Oil We**  **lls Gas**  **We lls** 

**Average Oil P**  **rodu c**  **tion Ra**  **te p**  **e r**  **Oil We**  **ll (** **bbl/day )**  **b C**  **rude Oil** 

**Sto ra**  **g e**  **V e**  **ss e**  **l VOC**  **E missions**  **( tp**  **y )**  **c Average** 

**C ond**  **e nsate**  **P rodu**  **c tion**  **Ra te**  **p e**  **r Gas**  **We ll**  **( bbl/day** **) b**  **C ond**  **e nsate** 

**Sto ra**  **g e**  **V e**  **ss e**  **l VOC**  **E missions**  **( tp**  **y )**  **c** 0 - 1 0 . 385 0 . 083 0 . 0183 0 . 038 1 - 2 1 . 34 0 . 287 0 . 0802 0 . 168 2 - 4 2 . 66 0 . 570 0 . 152 0 . 318 4 - 6 4 . 45 0 . 953 0 . 274 0 . 573 6 - 8 6 . 22 1 . 33 0 . 394 0 . 825 8 - 10 8 . 08 1 . 73 0 . 499 1 . 04 1 0 - 12 9 . 83 2 . 11 0 . 655 1 . 37 1 2 - 15 12 . 1 2 . 59 0 . 733 1 . 53 1 5 - 20 15 . 4 3 . 31 1 . 00 2 . 10 2 0 - 25 19 . 9 4 . 27 1 . 59 3 . 32 2 5 - 30 24 . 3 5 . 22 1 . 84 3 . 85 3 0 - 40 30 . 5 6 . 54 2 . 55 5 . 33 4 0 - 50 39 . 2 8 . 41 3 . 63 7 . 59 5 0 - 100 61 . 6 13 . 2 5 . 60 11 . 7 10 0 - 200 120 25 . 6 12 . 1 25 . 4 20 0 - 400 238 51 . 0 23 . 8 49 . 8 40 0 - 800 456 97 . 7 44 . 1 92 . 3 80 0 - 1 , 600 914 196 67 . 9 142 1 , 60 0 - 3 , 200 1 , 692 363 148 311 3 , 20 0 - 6 , 400 3 , 353 719 234 490 6 , 40 0 - 12 , 800 6 , 825 1 , 464 891 1 , 864 > 12 , 80 0 d 0 0 0 0 Minor discrepancies may be due to rounding. aBOE=Barrels of Oil Equivalent b Oil and c onden s at e produ ction rates publi shed by EI A. “US T o t al Di stribut ion of W ells by Production Ra t e Bra cke t. ” htt p ://www . eia . doe .g o v/

pub/oil_g a s/

pe tro sy st em

/u s

_t able . html. c Oil st orag e v e ss el V OC emi ss ion f a ct or = 0.21 4 t

py V O C/ bbl/ da y . C onden s at e storag e v e ss el V OC emi ss ion f a ct or = 2.0 9 t p y/ bbl/day . dThere were no new oil and g as well c omple t ions in 200 9 f or this rate c at e g ory . There f ore, av erag e produ ction rates were s et t o zero.***E.O. 12866 Review

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4 - 6 Storage Vessels 

### 4.3 **Available Controls and Regulatory**  **A pproaches**  In anal yz ing available controls for storage vessels, we reviewed information obtained in support of the 2012 NSPS and the 2013 NSPS reconsideration actions, control techniques identified in the Natural Gas STAR program , and existing state regulations that require control of VOC emissions from storage vessels in the ONG source category . Section 4.3.1 presents a discussion of the available VOC emission controls for storage vessels in the ONG source category . Section 4.3.2 includes a summary of the federal, state and local regulatory approaches that control VOC emissions for ONG source category storage vessels. **4.3.1 Available VOC Emission Control Options**  The options generall y used to limit the amount of VOC vented are to (1 ) route emissions from the storage vessel to any enclosed portion of a process where emissions are recycled, recovered, or reused in the process “route to a process”) (e.g., b y installing a vapor recovery unit (VRU) that recover s vapors from the storage ve ssel); and (2) route em issions from the storage vessel to a combu stor. One of the clear advantages the first option has over the second option is that it results in a cost savings associated with the recycled, recovered, and reused natural gas, rather than the loss and destruction of the natural gas by combustion. Combustion and partial combustion of organic pollutants also creates secondary pollutants including nitrogen oxides, carbon monoxide, sulfur oxides, carbon dioxide and smoke/particulates. These em ission control methods are described below along with their emission reduction control effectiveness as they apply to storage ves sels in the ONG source category and the potential cost s associated with the ir installation and operati on . **4.3.1.1 Routing Emis**  **sions to a Process via a Vapor Recovery Unit (VRU)**  Description One option for controlling storage vessel emissions in the ONG production segment is to route vapors from the storage vessels back to the inlet line of a separator, to a sales gas line, or to some other line carrying hydrocarbon fluids. Where a compressor is used to boost the recovered vapors into the line, this is o ften referred to as a VRU. 13 Ty pically with a VRU , hydrocarbon vapors are drawn out of the storage vessel under low pressure and are piped to a separator, or

13 Am erican Petroleum Institute . Letter to Bruce Moore, SPPD/OAQPS/EPA from M. Todd, API. Re: Oil and Natural Gas Sector Consolidated Rulemaking . Docket ID No.EPA - HQ - OAR - 2010 - 05 05 .***E.O. 12866 Review

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4 - 7 Storage Vessels suction scrubber, to collect any condens ed liquids, which are usually recycled back to the storage vessel. Vapors from the separator flow through a compressor that provides the low - pressure suction for the VRU sy stem where the recovered hydrocarbons can be transported to various places, including a sales line and/or for use on - site . Ty pes of VRUs inclu de conventional VRUs and venturi ejector vapor recovery units (EVRU TM ) or vapor jet sy stems. 14 Decisions on the ty pe of VRU to use are based on the applicability

needs ( e.g., an EVRU TM is recommended where there is a high pressure gas compressor with excess capacity and a vapor jet VRU is recommended where there is produced water, less than 75 million cubic feet ( Mcf ) /day gas and discharge pressures below 40 pounds per square inch gauge (psig). The reliability and integrity

of the compressor and suction scrubber and integrity of the lines that connect the tank to the compressor will affect the effectiveness of the VRU sy stem to collect and recycle vapors. 15 A conventional VRU is equipped with a control pilot to shut down the compressor and permit the back flow of vapors into the tank in order to prevent the creation of a vacuum in the top of a tank when liquid is withdrawn and the liquid level drops. Vapors are then either sent to the pipe line for sale or used as on - site fuel. Figure 4.1 presents a diagram of a conventional VRU installed on a single crude oil storage vessel (multiple tank installations are also common). 16

14 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Installing Vapor Recovery Units. Natural Gas STAR Program. Source Reduction Training to Interstate Oil and Gas Compact Commission Presentation. February 27, 2009. 15 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Installing Vapor Recovery Units on Storage Tanks . Natural Gas STAR Program. October 2006. http://www.epa.gov/gasstar/documents/ll_final_vap.pdf . 16 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Installing Vapor Recovery Units on Storage Tanks . Natural Gas Star Program. October 2006. http://www.epa.gov/gasstar/documents/ll_final_vap.pdf .***E.O. 12866 Review

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4 - 8 Storage Vessels **Figure 4 -**  **1 . Conventio**  **nal Vapor Recovery System**  Control Effectiveness VRUs have been shown to reduce VOC emissions from storage vessels b y over 95 percent and some states require that a VRU used to control VOC emissions from ONG storage vessels achieve a 98 percent reduction in VOC emissions . 17 , 18 However, we recognize that a VRU generally

does not operate 100 percent of the time due to maintenance and repair down time . A VRU recovers hydrocarbon vapors that potentially can be used as supplemental burner fuel, or the vapors can be condensed and collected as condensate that can be sold. If natural gas is recovered, it can be sold as well, as long as a gathering line is availabl e to convey the recovered salable gas product to market or to further processing. However, a VRU cannot be used in all instances. Some conditions that affect the feasibility of the use of a VRU are: availability

of electrical service sufficient to power th e compressor; fluctuations in vapor loading caused b y surges in throughput and flash emissions from the storage vessel; potential for drawing

17 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Installing Vapor Recovery Units on Storage Tanks. Natural Gas Star Program. October 2006. http://www.epa.gov/gasstar/documents/ll_final_vap.pdf . 18 Supplement to the Wyoming Air Quality Standards and Regulations (WAQSR). Oil and Natural Gas Production Facilities. Chapter 6, Section 2 Permitting Guidance . Revised March 2010.***E.O. 12866 Review

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4 - 9 Storage Vessels air into condensate storage vessels causing an explosion hazard; and lack of appropriate destination or use for th e vapor recovered. Cost Impacts Cost data for a VRU that were used in support of the 2012 NSPS obtained from an i nitial e conomic i mpact analy sis prepared for proposed state - only revisions to a Colorado regulation are presented here . 19 We assumed c ost inform ation contained in the Colorado EIA to be g iven in 20 12 dollars. According to the Colorado economic impact anal ys is , the purchased equipment cost of a VRU was estimated to be $90,000 . Total capital investment, including freight and design and installation was estimated to be $102,802 . Inaddition, we included an estimated storage vessel retrofit cost of $68,736 assuming that the cost of retrofitting an existing storage vessel was 75 percent of the purchased equipment cost (e.g., VRU capital cost s and freight and design cost). 20 These co st data are presented in Table 4 - 3 . We estimated t otal annual costs using 2012 dollars to be $ 28,230 /year without recovered natural gas savings, and $24,848 with recovered natural gas savings . The uncontrolled emissions from a storage vessel are largel y dependent on the bbl/ye ar throughput (see Table 4 - 2), which greatl y influence s both the controlled emissions and the cost of control per ton of VOC reduced. Costs may vary due to VRU design capacity , s ystem configuration and indi vidual site needs and recovery opportunities. Based on the estimated total annual costs, we estimated the costs of routing emissions from an existing storage vessel to a VRU (assuming a 95 percent reduction of VOC emissions) for a storage vessel that emits four tpy , six tpy , eight tpy , 10 tpy , 11 tpy , 12 tpy and 25 tp y. We estimated the cost of control without savings b y dividing the total annual cost s without savings by the tons per year (tp y) reduced. The cost of control with savings is calculated b y assuming a 95 percent reduction of VOC emissions by the VRU and converting the reduced VOC emissions to natural gas savings. Table 4 - 4 presents the estimated natural gas savings and the VOC cost per ton with and without savings.

19 Initial Economic Impact Analysis for Proposed Revisions to the Colorado Air Quality Control Commission Regulation Number 7, Emissions of Volatile Organic Compounds . November 15, 2013. 20 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Installing Vapor Recovery Units on Storage Tanks. Natural Gas Star Program. October 2006. http://www.epa.gov/gasstar/documents/ll_final_vap.pdf .***E.O. 12866 Review

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4 - 10 Storage Vessels **Table 4 -**  **3 .**  **Total Capital Investment and Total Annual Cost s**  **of a Vapor Recovery Unit System**  **Cost Item a**  **Cost (**  **$2012 )**  **Capital Cost**

**s Items**  VRU a $90, 000 Freight and Design a $1,648 VRU Installation a $11,154 Storage Vessel Retrofitb $68,736 Total Capital Investment $171,538 **Annual Cost**

**s Items**  Maintenance $9,396 Capital Recovery (7 percent interest, 15 year equipment life) ($/yr) $18,834 Recovered Natural G as (including natural gas liquid) ($/yr) c ($3,382) **Total Annual Cost**

**s w/o Savings ($/yr)**  **$28,230 Total Annual Cost** 

**s w/ Savings ($/yr)**  c **$24,848 c**  a. Cost data from Initial Economic Impact Analysis (EIA) for proposed revisions to Colorado Air Quality Control Commission Regulation Number 7, Submitted with Request for Hearing Documents on November 15, 2013. b. Assumes the storage vessel retrofit cost is 75 percentof the purchased equipment price (assumed to include vent system and piping to route emissions to the control device) . Retrofit assumption from Exhibit 6 of the EPA Natural Gas Star Lessons Learned, Installing Vapor Recovery Units on Storage Tanks, October 2006. c Based on the EIA’s recovered natural gas fuel costs of $3.5/Mcf (Henry Hub Spot Price

– August 2013) and average tank battery size of 63.2 tpy

– based on 3 - year average of APEN data on storage tanks greater than or equal to 6 tpy (uncontrolled VOC).***E.O. 12866 Review

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4 - 11 Storage Vessels **Table 4 -**  **4 .**  **Costs of Routing Emissions to and Existing Storage Vessel to a VRU ($/Ton of VOC Reduced)**  **Storage Vessel Emissions**  **(tpy) Cost per to**  **n of VOC Reduced ($2012**

Without Savings Natural Gas Savings (Mscf/yr) a With Savings b 4 $6,539 792.0 $3,371 6 $4,359 1187.9 ($393) 8 $3,269 1583.9 ($3,067) 10 $2,616 1979.9 ($5,304) 11 $2,378 2177.9 ($6,334) 12 $2,180 2375.9 ($7,324) 25 $1,046 4949.8 ($18,753) a. The natural gas savings was calculated by assuming a VOC reduction of 95% and dividing by the VOC/methane weight ratio of 0.278 to determine the amount of methane reduction that would be reduced. The methane emission reductions were converted to volumetric natural gas reductions assuming a natural gas density of 0.02082 tons/Mcf and a 82.9 volume percent conversion factor of methane to natural gas. b. Assumes a natural gas price of $4.00 per Mcf. Additionally , if a VRU is used to control VOC emissions from multiple storage vessels, the VOC emissions cost of control would be reduced because the cost for the additional storage vessel(s) would onl y include the storage vessel retrofit costs, and the overall VOC emission reductions would increase. **4.3.1.2 Routing Emissions to a Combustion Device**  Description and Control Effectiveness Combustors (e.g., enclosed combus tion devices, thermal oxidizers and flares that use a high - temperature oxidation process) are also used to control emission s from storage vessels. Combustors are used to control VOC in many industrial settings, since the combustor can normally handle fluctuations in concentration, flow rate, heating value and inert species content. 21 For this analy sis, we assume d that the typ es of combustors installed for the ONG source category

achieve at least a 95 percent control efficiency **.** 22 A ty pical combustor used to control emissions from storage vessels in the ONG source category is an enclosed combustion system. The ba sic components of an enclosed combustion 21 U.S. Environmental Pro tection Agency. AP 42, Fifth Edition, Volume I, Chapter 13.5 Industrial Flares . Office of Air Quality Planning & Standards. 1991. 22 U.S. Environmental Protection Agency. Air Pollution Control Technology Fact Sheet: FLARES . Clean Air Technology Center.***E.O. 12866 Review

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4 - 12 Storage Vessels sy stem include (1) piping for collecting emission source gases , (2) a single - or multiple - burner unit, (3) a stack enclosure, (4) an ignito r to ignite the mixture of emission source gas and air, and (5) combustor fuel/piping (as necessary). Figure 4 - 2 presents a schematic of a ty pical dual - burner enclosed combustion sy stem. Thermal oxidizers, also referred to as direct flame incinerators, thermal incinerators, or a fterburners could also be used to control VOC emissions. Similar to a basic enclosed combustion device, a thermal oxidizer uses burner fuel to maintain a high temperature (typicall y 800 - 850°C) within a combustion chamber. The VOC laden emission source gas is injected into the combustion chamber where it is oxidized (burned), and then the combustion products are exhausted to the atmosphere. Figure 4 - 3 provides a basic schematic of a thermal oxidizer. 23 Cost Impacts For combustors, we also obtained cost data from the initial EIA prepared for s tate - onl y revisions to the Colorado regulation. 24 In addition to these cost data, we added a line - item for operating labor , a surveillance s ys tem, and data management . This is consistent with the guidelines outlined in the EPA’s Office of Air Quality Planning and Standards ( OAQPS ) Control Cost Manual (OCCM) for combustion devices and the EIA prepared for the 2012 NSPS . 25 However, OCCM guidelines specify that 630 operating labor hours per year for a combustion device, which we believe is unreasonable because many of these sites are unmanned and would most likely

be operated remotely . Therefore, we assumed that the operating labor would be more similar to that estimated for a condenser in the OCCM, 130 hours per year. We estimated a total capital investment of $ 100,986 and a total annual cost s of $ 22,228 /year. We included an additional cost of $68,736 (as discussed previously for VRUs) to estimate the cost of retrofitting an existing storage vessel to accommodate the use of a combustion device. T able 4 - 5 presents these co st data .

23 U.S. Environmental Protection Agency. Technology Transfer Network. Clearinghouse for Inventories and Emission Factors. Thermal Oxidizer . Website: cfpub.epa. gov/oarweb/mkb/contechnique.cfm. 24 Initial Economic Impact Analysis for Proposed Revisions to the Co lorado Air Quality Control Commission Regulation Number 7, Emissions of Volatile Organic Compounds . November 15, 2013. 25 U.S. Environmental Protection Agency. OAQPS Control Cost Manual: Fourth Edition (EPA 450/3 - 90 - 006, January 1990). Research Triangle Park, NC.***E.O. 12866 Review

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4 - 13 Storage Vessels **Figure 4 -**  **2 . Schematic of a Typical Enclosed Combustion System** ***E.O. 12866 Review

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4 - 14 Storage Vessels **Figure 4 -**  **3 . Basic Schematic of a Thermal Oxidize**  **r*****E.O. 12866 Review

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4 - 15 Storage Vessels **Table 4 -**  **5 .**  **Total Capital Investment and Total Annual Cost s**  **of a Combustor 26** 

**Cost Item a**  **Cost (**  **$ 2012)**  **Capital Cost**

**s Items**  Combustor a $ 18 , 169 Freight and Design a $1,648 Auto Ignitor a $1,648 Surveillance System b ,c,d $3,805 Combustor Installation a $6,980 Storage Vessel Retrofit e $68,736 Total Capital Investment $100,986 **Annual Cost**

**s Items**  Operating Labor f $5,155 Maintenance f $4,160 Pilot Fuel a $768 Data Management c $1,057 Capital Recovery (7% interest, 15 year equipment life) ($/yr) $11,088 **Total Annual Cost**

**s ($/yr)**  $ 22,228 a. Cost data from Initial Economic Impact Analysis for proposed revisions to Colorado Air Quality Control Commission Regulation Number 7, Submitted with Request for Hearing Documents on November 15, 2013. b . Surveillance system identifies when pilot is not lit and attempt s to relight it, documents the duration of time when the pilot is not lit, and notifies and operator that repai rs are necessary. c U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New Source Performance Standards . April 2012. EPA Docket ID No. EPA - HQ - OAR - 2010 - 0505 - 4550. d . Cost obtained from 2012 TSD and escalated using the change in GDP: Implicit Price Deflator from 2008 to 2012 (%)(which was 5.69%). Source: FRED GDP: Implicit Price Def lator from Jan 2008 to Jan 2012 (http://research.stlouisfed.org/fred2/series/GDPDEF/# ) e Retrofit cost obtained from Storage Vessel Retrofit in Table 4 - 3 (assumed to include vent system and piping to route emissions to the control device) . f . Operating labor consists of labor resources for technical operation of device (130 hr/yr) and supervisory labor (15 percent of technical labor hours) . M aintenance labor hours are assumed to be the same as operating labor (130 hr/yr). Labor rates are $3 2 . 00 /hr (for technical and maintenance labor) and $5 1 . 03 (supervisory labor) and were obtained from the U.S. Department of Labor, Bureau of Labor Statistics, Employer Costs for Employee Compensation, Dec ember 2012 . The uncontrolled emissions from a storage vessel are largel y dependent on the bbl/year throughput (see Table 4 - 2), which greatly influences both the controlled emissions and cost of control. Based on the estimated total annual costs, we estimat ed the costs of routing emissions 26 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New Source Performance Standards . April 2012. EPA Docket Number EPA - HQ - OAR - 2010 - 0505 - 4550.***E.O. 12866 Review

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4 - 16 Storage Vessels from an existing storage vessel to a combustion device (assuming a 95 percent reduction of VOC emissions) for a storage vessel that emits four tpy, six tpy , eight tpy , 10 tpy , 11 tpy , 12 tpy and 25 tpy . We estimated the co st of control without savings by dividing the total annual cost s without savings b y the tpy reduced. Table 4 - 6 presents these costs. The VOC emissions cost of control per ton of VOC reduced would be less if a combustion device is used to control VOC emissi ons from multiple storage vessels because the cost for the additional storage vessel(s) would only

include storage vessel retrofit costs, and the overall VOC emission reductions would increase. **Table 4 -**  **6 .**  **Costs of Routing Emissio ns to and Existing Storage Vessel to a Combustion**  **Device ($/ton of VOC Reduced) Storage Vessel Emissions** 

**(tpy) Cost**  **per ton of VOC Reduced (**  **$2012; Without Savings )**  4 $5,849 6 $3,900 8 $2,925 10 $2,340 11 $2,127 12 $1,950 25 $936 **4.3.2 Existing**  **Federal, State and Local Regulations 4.3.2.1**  **Federal Regulations that Specifically Require Control of VOC** 

**Emissions** Under the 2012 NSPS/2013 NSPS Reconsideration, new or modified storage vessels with potential to emit VOC emissions of six tpy or more must reduce VOC emissions by at least 95 percent, or demonstrate emissions from a vessel have dropped to less than four tpy of VOCs without emission controls for 12 consecutive months.***E.O. 12866 Review

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4 - 17 Storage Vessels **4.3.2.2 State and Local Regulations**  **that Specifically Re quire Control of VOC** 

**Emissions 27**  States may

have permitting restrictions on VOC emissions that may apply to an emissions source as a result of an operating, NSR nonattainment , or PSD permit (e.g., on a case by- case basis) based on air quality maintenance or improvement goals of an area. Permits specify what construction is allowed, what emission limits must be met, and how the source must be operated . To en sure that sources follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements. Th e env ironment al re g

u lat i o n s in nine top producing ONG st a t es (sometimes with varying local ozone nonattainment area/concentrated area development requirements) ( see Table 4 - 7) require the control of VOC emissions from storage vessels in the ONG source category . These states include California, Colorado, Kansas, Louisian a, Montana, North Dakota, Oklahoma, Texas and Wyoming. All but Wyoming require 95 percent emission control with the application of a VRU or combustion (Wyoming requires 98 percent control of emissions using a VRU or combustion). Ta b le 4 - 7 p re s ent s a b rief summary o f th e s t o rag e v e ss el emission control applicability cutoffs in re gu l ati o n s f

rom th e s e nine s t a

t e s . Fo ur st a

t es (C olora d o, M o nt an a, T e x a s an d Wyomi n g ) h av e a

pp li c ab il ity thre s h ol d s in t erms of V O C emi ss io n s . Th e remai n ing f i v e s t ates h av e s tora g e v e ss el re gu l a t io n s t h at are in t erms o f t ank c h ara c t eri s ti cs , s u c h as v a p or p re ss u

re, t ank s i z e or t a

nk c o nt ent s . **Table 4 -**  **7 .**  **Summary of Storage Vessel Regulations from Nine**  **States S**  **t a** **t e** **/ L**  **oc a**  **l Au**  **t ho**  **r i**  **t y**  **Ap p**  **li c**  **a b**  **i l** **i ty**  **T h**  **r e**  **sh o**  **l d**  T e x as App lies t o s t o ra g e v e ss e l s wi th V O C emi ss i o n s gre ater th a n 2 5 t py. C a lif o rnia Bay Ar e a AQ MD App lies t o s t ora g e v e ss e l s wi th c ap ac i ty gre at er t h an 264 g al l o n s. C a lif o rnia F eath e r Ri ver A Q M D App lies t o s t ora g e v e ss e l s wi th c ap ac i ty gre at er t h an 39,6 3 0 g all o n s.

27 Brown, Heather, EC/R Incorporated. Memorandum prepared for Bruce Moore, EPA/OAQPS/SPPD/FIG. Revised Analysis to Determine the Number of Storage Vessels Projected to be Subject to New Source Performance Standards for the Oil and Natural Gas Sector.***E.O. 12866 Review

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4 - 18 Storage Vessels

**S t**  **a t**  **e /** **L oc**  **a l**  **Au t**  **ho r** **i t** **y Ap**  **p li**  **c a**  **b i** **l i** **ty T**  **h r**  **e sh**  **o l**  **d** C a lif o rnia M ont er e y Bay Un i f

i e d AP CD App lies t o s t ora g e v e ss e l s wi th c ap ac i ty gre at er t h an 39,6 3 0 g all o n s. C a lif o rnia Sa cr ame nto Me t

r opo l itan AQ M D App lies t o s t ora g e v e ss e l s wi th c ap ac i ty gre at er t h an 40,0 0 0 g all o n s. C a lif o rnia San J o a qu in Va ll e y Unifi e d AP CD App lies t o s t ora g e v e ss e l s wi th c ap a c i ty gre a t er t h an 1,1 0 0 g allo n s. C a lif o rnia Santa Bar b ar a Coun

ty AP CD App lies t o all s t ora g e v e s s els in t ank b att ery ( in c ludi n g

wa s h tanks , p r o du c ed wat er t anks , a n d wa s t e water t anks ). C a lif o rnia S outh C o a st AQ M D App lies t o s t ora g e v e ss e l s wi th c ap ac i ty gre at er t h an 39,6 3 0 g all o n s wi t

h a tr ue vap or p re ss ure of 0 . 5 p s ia or great er and s tora g e ve ss els wi th a c ap ac ity gre ater t h an 19,8 1 5 gallons wi t

h a t r ue v a p or p re ss u

re o f 1 . 5 p s ia or great er. C a lif o rnia Ve ntur a C ounty AP CD App lies t o all s t o ra g e v e ss e l s. Requirements depend on gallon capacity and true vapor pressure of material contained in vessel. C a lif o rnia Yo l o - S o l ano AQ M D App lies t o s t ora g e v e ss e l s wi th c ap ac i ty gre at er t h an 40,0 0 0 g all o n s. No rth D akota ND AC 3 3 - 1 5 - 0 7: sub me rg ed f illi n g re q uire me nt s t o c o ntr o l V OC s f

or t anks > 1,0 0 0 g allons. Federal Implementation Plan (FIP): Fort Berthold Indian Reservation Applies to all storage vessels (except those covered by NSPS subpart OOOO). There is no minimum threshold under the final FIP. L oui s i ana App l ies t o s t o ra g e v e ss e l s more th a n 250 g allo n s u

p to 40,0 0 0 g all o n s wit

h a max im

um tr u e v ap or p re ss u

re o f 1 . 5 p s ia or gre ater. O kl aho ma App lies t o s t ora g e v e ss e l s wi th c ap ac i ty gre at er t h an 40,0 0 0 g all o n s (in ozone nonattainment areas). Wyo mi ng – S t ate wi de App lies t o s t o ra g e v e ss e l s wi th gr e at er t h an or e q u al to 1 0 tp y V O C wi t

h in 60 d ay s o f s t a

r tu p /mo di f i c at i o n. Wyo mi ng – Conc e nt

rat e d Deve lop me nt Ar ea App lies t o s t o ra g e v e ss e l s wi th gr e at er t h an or e q u al to 8 tp y V OC , wit

h in 60 d ay s of s t art

u p/mo di f i c ati o n. Kans as Perman e nt f i x e d roof s t o ra g e t a

nks >4 0 ,000 g all o n s a

nd e xt ern al f l oatin g r o of s t ora g e t a

nks.***E.O. 12866 Review

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4 - 19 Storage Vessels

**S t**  **a t**  **e /** **L oc**  **a l**  **Au t**  **ho r** **i t** **y Ap**  **p li**  **c a**  **b i** **l i** **ty T**  **h r**  **e sh**  **o l**  **d** Co l o r a do C o nd en s at e ta nks wi th u

n c o nt roll e d V O C emi ss i o n s > 20 tp y ( 2 tp y lo c at e d at g as pro c e ss i n g p lant s in o z on e n o n att ainment a

rea s ). M ont a na App lies t o oil or c o nd en s ate s t ora g e tanks wi th a PTE great er t h an 15 t p y V O C. 

### 4.4 **Recommended RACT Level of Control** As discussed in section 4.3.2 of this chapter, existing federal and state and local regulations already require the reduction of VOC emissions at or greater than a 95 percent reduction of VOC emissions. While t echnologies such as a VRU and combustor (discu ssed in section 4.3.1 of this chapter) may achieve a 98 percent reduction of VOC emissions ( and states su ch as Wyoming require 98 percent VOC emissions reduction level of control for storage vessels ). We recognize that a 98 percent reduction of VOC emissio ns may not be achieved at all times. However, a 95 percent reduction of VOC emissions from storage vessel sources in the ONG source category

has already been demonstrated to be achieved consistently . Thus, we believe that a 95 percent reduction of VOC emis sions from storage vessels in the ONG source category is a reasonable recommended RACT level of control based on the wide use of this level of control in federal and state regulations that apply to a majority of the ONG source category . Although sources h ave a choice on how they meet the recommended RACT level of control, the technologies that will likely be used to meet the recommended RACT level of control for ONG source category storage vessels are routing emissions to the process via a VRU or routing e missions to a combustion device. In general, we believe it is unlikely that an owner or operator of a storage vessel subject to the recommended RACT level of control would choose to comply

by using a condenser or carbon adsorber given the high base equipment and operating costs compared to the costs of the use of a VRU and/or a combustion device . In addition, condensers and carbon adsorbers require constant and reliabl e sources of electricity which is generall y not available at remote well sites. As discussed in section 4.2.2 of this chapter, the VOC emissions from storage vessels vary significantl y, depending on the rate of liquid entering and passing through the vesse l (i.e., its throughput), the pressure of the liquid as it enters the atmospheric pressure storage vessel, the liquid’s volatility

and temperature of the liquid. Some storage vessels have negligible emissions,***E.O. 12866 Review

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4 - 20 Storage Vessels such as those with very

little throughput and/ or handling heavy liquids entering at atmospheric pressure. Existing state regulations that apply to storage vessels in the ONG source category apply to all storage vessels in a tank battery , or include an applicability threshold based on (1) capacity , (2) the vapor pressure of liquids contained in a storage vessel of a specified capacity , and (3) the PTE of an individual storage vessel. In order that the recommended RACT level of control only applies to existing storage vessels that emit levels that would result in a reasonable cost of control, we evaluated the cost of control at four tp y, six tpy, eight tp y, 10 tp y, 11 tpy, 12 tp y and 25 tp y using the estimated total annual costs for routing VOC emissions to a process via a VRU and to a combustion device. For storage vessels that emit four tpy , this would result in an estimated cost of control of between $3,400 (considering natural gas savings) and $6,500 per ton of VOC reduced without considering cost savings. For a storage vessel that emits six tpy, this would result in an estimated cost of control savings of $393 per ton of VOC reduced to $4,359 per ton of VOC reduced without considering natural gas cost savings. (See sections 4.3.1.1 and 4.3.1.2). Based on our anal ys es and anal ys es conducted in support of the 2013 NSPS Reconsideration, six tpy was determined to be a reasonable control applicability threshold for storage vessels. Thus, we recommend that the 95 percent VOC emission control of storage vessels only appl y to storage vessels that emit > six tpy VOC emissions. The VOC cost of control per ton of VOC reduced would be less if a combustion device and VRU is used to control VOC emissions from multiple storage vessels because the cost for the additional storage vessels would only include storage vesse l retrofit costs, and the overall VOC emission reductions would increase. In summary , we recommend the following as RACT for storage vessels in the ONG source category

is as follows: 1) RACT for Condensate Sto rage Vessels : Reduce emissions by 95 percent from condensate storage vessels with a PTE > six tpy of VOC. 2) RACT for Crude Oil Storage Vessels : Reduce emissions by 95 percent from crude oil st orage vessels with a PTE > six tpy of VOC.***E.O. 12866 Review

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4 - 21 Storage Vessels 

### 4.5 **Factors to Consider in Developing Storage Vessel Compliance Procedure**  **s 4.5.1**  **Compliance Recommendations When Using a Control Device**  Improper design or operation of the storage vessel and its control sy stem can result in occurrences where peak flow overwhelms the storage vessel and its capture sy stems, resulting in emissions that do not reach the control device, effectivel y reducing the control efficiency . We believe that it is essential that operators emplo y properly designed, sized and operated storage vessels to achieve effective emission control. We believe that such efforts on the part of owners and operators can result in more effective control of VOC emissions from storage vessels. In order to ensure that VOC emissions are reduced by at least 95 percent (the recommended RACT level of control) from a storage ves sel when using a control device or other control measure (such as routing to a process), the storage vessel should be equipped with a cover that is connected through a closed vent sy stem that routes emissions to the control device (or process) that meets the RACT level of control . We recommend cover, closed vent sy stem and control device design and compliance measures to ensure that control measures meet the RACT level of control. Recommended c over and closed vent sy stem design and operation measures are sp ecified in section s 4.5.1.1 and 4.5.1.2 . Recommended control device operation and monitoring provisions for specified controls to ensure compliance are presented in section s 4.5.1.3 and 4.5.1.4. The appendix to this document presents example model rule language that incorporates compliance elements recommended in this section that states may choose to use in whole or in part. **4.5.1.1 Recommendations for Cover Design**  The cover and all openings on the cover (e.g., access hatches, sampling ports, pressure relief valves and gauge wells) should form a continuous impermeable barrier over the entire surface area of the liquid in the storage vessel or wet seal fluid degassing s ystem. Each cover opening should be secured in a closed, sealed position (gasket lid o r cap) whenever material is in the unit except when it is necessary to open as follows: 1) To add material to or remove material from the unit (including openings necessary to equalize or balance the internal pressure of the unit following changes in the leve l of material in the unit); 2) To inspect or sample the material in the unit;***E.O. 12866 Review

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4 - 22 Storage Vessels 3) To inspect, maintain, repair, or replace equipment located in the unit ; or 4) To vent liquids, gases or fumes from the unit through a closed - vent sy stem designed and operated in acco rdance specified control device requirements (see section 4.5.1. 2 ) or to a process. We recommend that you require the st orage vessel thief hatch be equipped, maintained and operated with a weighted mechanism or equivalent, to ensure that the lid remains properly seated . We also recommend that you require the gaske t material for the hatch be selected based on composition of the fluid in the storage vessel and weather conditions. We recommend requiring olfactory , visual and auditory inspections of covers for defects that could result in air emissions on a monthly basis. We recommend requiring that any detected defects be repaired as soon as technicall y feasible to minimize emissions (and prior to the end of the next shutdown). **4.5.1.2 Recommendations for Clos**  **ed Vent Systems** The closed vent s ys tem should be designed and operated with no detectable emissions (which can be monitored by monthly olfactory , visual and auditory inspections) and should be in operation at least 95 percent of the year. We recommend requ iring that any detected defects be repaired as soon as technically feasible to minimize emissions (and prior to the end of the next shutdown). With the exception of low leg drains, high point bleeds, anal yz er vent, open - ended valves and safety devices, i f the closed vent s ys tem contains one or more b ypass devices that could be used to divert all or a portion of the gases, vapors, or fumes from entering the control device or to a process, we recommend requiring owners and operators either: 1) Install, calibrate, maintain and operate a flow indicator at the inlet to the bypass device that could divert the stream away from the control device or process to the atmosphere that sounds an audible and visual alarm, or, initiates notification via remote alarm to the nearest field office, when the by pass device is open such that the stream is being, or could be, diverted away

from the control device or process to the atmosphere; or 2) Secure the b yp ass device valve installed at the inlet to the by pass devic e in the non diverting position using a car- seal or a lock - and - key ty pe configuration. We recommend requiring b ypass devices to be equipped with flow indicators that sound an alarm when***E.O. 12866 Review

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4 - 23 Storage Vessels the stream is diverted away from the control device or process to the atmosphere and that records be maintained of times when the alarm sounds. **4.5.1.3 Recommendations When**  **“Routing to a Process” to a VRU**  Routing to a process would entail routing emissions via a closed vent s ys tem to any enclosed portion of a process unit where the emissions are predominantl y rec ycled and/or consumed in the same manner as a material that fulfills the same function in the process and/or transformed b y chemical reaction into materials that are not regulated materials and/or incorporated into a product and/or recovered. Vapor recovery units and flow lines that “route emissions to a process” would be considered part of the process and would not be considered control devices that are subject to standards, but the cover and closed vent design, operation and monitoring requirements specified in sections 4.5.1.1 and 4.5.1.2 would apply . **4.5.1.4 Recommendations for**  **Control Device Operation and Monitor ing**  If a control device is used to comply with the recommended RACT level of control, the device should be required to operate at all times when gases, vapors, and fumes are vented from the storage vessel affected facility through the closed vent sy stem to the control device. The following paragraphs present select emission control options and suggest ed operation and monitoring requirements, as appropriate to ensure compliance with the RACT level of control. Enclosed Combustion Devices If an enclosed combustion device ( e.g . , thermal vapor incinerator, catal ytic vapor incinerator, boiler, or process heater) is used to meet the suggested RACT level of control, it should be designed to reduce the mass content of VOC emissions b y 95 percent or greater; and (1) maintained in a leak free condition, (2) installed and operated with a continuous burning pilot fl ame, and (3) operated will no visib le emissions . We recommend encouraging the use of electronic ignition devices to reduce the amount of natural gas being combusted. The visible emissions test (using section 11 of EPA Method 22, 40 CFR part 60, appendix A - 7), inspection, repair and mainten ance activities for each unit are recommended to be required and recorded i n a maintenance and repair log that can be made available for inspection . Following return to operation from maintenance or repair activity , eac h device should be required to pass a Method 22 visual observation test as described in this paragraph.***E.O. 12866 Review

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4 - 24 Storage Vessels We recommend requiring that sources meeting the RACT level of control by routing emissions to a combustion device conduct performance tests and/or desi gn anal ys es that demonstrate that the combustion device being used meets the required RACT level of control (see section F of the appendix to this document for performance testing procedures for control devices that we recommend be used to demons trate perf ormance requirements) . Vapor Recovery

Devices Vapor recovery

devices ( e.g . , refrigerated condenser or carbon adsorption system) or other non - destructive control device must be designed and operated to reduce the mass content of VOC in the gases vented t o the device b y 95 percent by weight or greater. If a condenser is used, the condenser should be required to meet site - specific performance requirements (similar to those specified in 40 CFR 60.5417(f)(2)) and, if a carbon adsorption sy stem is used, owners o r operators should be required to establish a carbon replacement schedule for its carbon adsorption sy stem that ensures continued compliance with the required RACT level of control. Condensers should be required to be equipped with a temperature monitoring device that continually records temperatures to ensure optimum operation and emission control is maintained (temperature sensor should be located in the exhaust vent from the condenser and should have a minimum accuracy of + one percent of the temperature being monitored in ° C, or + 2.8 ° C, whichever value is greater). The carbon replacement schedule interval should be established using a performance test ( e.g., as specified in 40 CFR 60.5413(b)) so that it is based on the total carbon working capacity of the control device and source operating schedule.***E.O. 12866 Review

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5 - 1 Compressors 

### 5.0 **COM PRESSORS**  Compressors are mechanical devices that increase the pressure of natural gas and allow the natural gas to be transported from the production site, through the supply chain, and to the consumer. The types of compressors that are used by the ONG source categ ory as prime movers are reciprocating and centrifugal compressors. This chapter discusses the sources of VOC emissions from these compressors. This chapter also provides control techniques used to reduce VOC emissions from these compressors, along with cos ts and emission reductions. Finally , this chapter provides a discussion of our recommended RACT and the associated VOC emission reductions and cost impacts for both reciprocating and centrifugal compressors. 

### 5.1 **Ap plicability**  For the purposes of this guide line, the emissions and emission reductions discussed herein would appl y to centrifugal and reciprocating compressors in the ONG source category located between the wellhead and point of custody transfer to the natural gas transmission and storage segment. As noted in section 3.2 of c hapter 3 of this document, we did not evaluate RACT for compressors at the wellhead or in the transmission and storage segment in this guideline. Therefore, in the production segment, we only evaluated RACT for compressors at g athering and boosting station s. Further, because there are no centrifugal compressors reported in the GHG Inventory

for the production segment, we believe that reciprocating compressors are used almost exclusively

at gathering and boosting station s. As such we did not evaluate RACT for centrifugal compressors at gathering and boosting station s. 

### 5.2 **Process Description and Emission Sources 5.2.1**  **Process Description 5.2.1.1**  **Reciprocating Compressors** In a reciprocating compressor, natural gas enters the suction manifold, and then flows into a compression cylinder where it is compressed by a piston driven in a reciprocating motion by the crankshaft powered by an internal combustion engine. Emissions occur when natural gas leaks around the piston rod wh en pressurized natural gas is in the cylinder. The compressor rod packing s ys tem consists of a series of flexible rings that create a seal around the piston rod to prevent gas from escaping between the rod and the inboard cylinder head. However, over time,***E.O. 12866 Review

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5 - 2 Compressors during operation of the compressor, the rings become worn and the packaging s ys tem needs to be replaced to prevent excessive leaking from the compression cylinder. See Figure 5 - 1 for a depiction of a typical rod compressor packing s ys tem configuration . 28

**Figure 5 -**  **1 . Typical Reciprocating Compressor Rod Packing System Diagram**  **5.2.1.2 Centrifugal Compressors**  Centrifugal compressors use a rotating disk or impeller to increase the velocity of the natural gas where it is directed to a divergent duct section that converts the velocity energy to pressure energy . These compressors are primaril y used for continuous, stationary transport of natural gas in the processing and transmission sy stems. Many centrifugal compressors use wet (meaning oil) seals around the rotating shaft to prevent natural gas from escaping where the compressor shaft exits the compressor casing. The wet seals use oil which is circulated at high pressure to form a barrier against compressed natural gas leakage. The circulated oil entrains and

28 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Reducing Methane Emissions from Compresso r Rod Packing Systems . Natural Gas STAR Program. 2006.***E.O. 12866 Review

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5 - 3 Compressors adsorbs some compressed natural gas that may be released to the atmosphere during the seal oil recirculation process. Figure 5 - 2 illustrates the wet seal compressor configuration . 29

**Figure 5 -**  **2 .**  **Typical Centrifugal Compressor Wet Seal** Alternativel y, dry seals can be used in place of wet seals in centrifugal compressors. Dry seals prevent leakage b y using the opposing force created b y h ydrodynamic grooves and springs (see Figure 5 - 3). The hydrody n amic grooves are etched into the surface of the rotating ring affixed to the compressor shaft. When the compressor is not rotating, the stationary ring in the seal housing is pressed against the rotating ring by springs. When the compressor shaft rotates at high speed, compressed natural gas has onl y one pathway to leak down the shaft, and that is between the rotating and stationary rings. This natural gas is pumped between the grooves in the rotating and stationary

rings. The opposing force of high - pressur e natural gas pumped between the rings and springs trying to push the rings together creates a very thin gap between the rings through which little natural gas can leak. While the compressor is operating, the rings are not in

29 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Replacing Wet Seals with Dry Seals in Centrifugal Compressors . Natural Gas STAR Program. October 2006. http://epa.gov/gasstar/documents/ll_wetseals.pdf***E.O. 12866 Review

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5 - 4 Compressors **Figure 5 -**  **3 . Typical Centrifugal Compressor Tandem Dry Seal**  contact with each other, and therefore, do not wear or need lubrication. O - rings seal the stationary rings in the seal case. 30 Natural gas emissions from wet seal centrifugal compressors have been found to be higher than dry

seal compressors primaril y due to the off - gassing of the entrained natural gas from the oil. This natural gas is not suitable for sale and is either released to the atmosphere, flared, or routed back to a process. In addition to lower natural gas leakage (and therefore lower emissions), dry

seals have been found to have lower operation and maintenance costs than wet seal compressors because they are a mechanically

simpler design, require less power to operate, and are more reliable. For the same reasons we explained in the 2012 NSPS and the 2015 NSPS proposal, we are not recommending RACT for dry seal compressors and instead include the use of dry seal in place of a wet seal s ys tem as an available control option for reducing VOC emissions from wet seal centrifugal compressors (discus sed in section 5.3.1.2 of this c hapter). During the rulemakings for the 2012 NSPS and 2015 NSPS proposal, we found that the dry seal sy stem and the option of routing to a process both had at least 95 percent control efficiency .

30 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Replacing Wet Seals with Dry Seals in Centrifugal Compressors . Natural Gas STAR Program. October 2006. http://epa.gov/gasstar/documents/ll_wetseals.pdf***E.O. 12866 Review

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5 - 5 Compressors **5.2.2 Emissions Data**  **5.2.2.1 Summary of Major Studies and Emissions**  Several studies that have been conducted that provide leak estimates from reciprocating and centrifugal compressors. Table 5 - 1 lists these studies, along with the type of information contained in the study . Inaddition to these sources, we evaluated the peer reviewer and public comments received on the EPA’s white paper, “Oil and Natural Gas Sect or Compressors.” 31

**Table 5 -**  **1 . Major Studies Reviewed for Emissions Data**  **32 Report Name**  **Affiliation Year of**  **Report Activity** 

**Factors Emissions** 

**Data Control** 

**Options** Inventory of Greenhouse Gas Emissions and Sinks: 1990 - 2012 a EPA 2014 Nationwide X Greenhouse Gas Reporting Program (Annual Reporting; Current Data Available for 2011 - 2013) b EPA 2014 Facility - Level X X Methane Emissions from the Natural Gas Industryc GRI/EPA 1996 Nationwide X Natural Gas STAR Programd,e EPA 1993 - 2010 Nationwide X X Natural Gas Industry Methane Emission Factor Improvement Studyf URS Corporation, UT Austin, and EPA 2011 None Emission factors only Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production: Summary and Analysis of API and ANGA Survey Responses g API/ANGA 2012 Regional X h

31 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Compressors. Report for Oil and Na tural Gas Sector Compressors Review Panel . Office of Air Quality Planning and Standards (OAQPS). April 2014. Available at http://www.epa.gov/airquality/oilandgas/2014papers/ 32 U.S. Enviro nmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New Source Performance Standards . Ap ril 2012. EPA Docket Number EPA - HQ - OAR - 2010 - 0505 - 4550.***E.O. 12866 Review

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5 - 6 Compressors**Report Name Affiliation**  **Year of Report**  **Activity**

**Factors Emissions** 

**Data Control** 

**Options** Economic Analysis of Methane Emissions Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries i ICF International (Prepared for the Environmental Defense Fund (EDF) 2014 Regional X X

a. U.S Environmental Protection Agency. Greenhouse Gas Inventory: Emission and Sinks 1990 - 2012. Washington, DC. b. U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: Climate Change Division. Washington, DC. November 2014. c . 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. d. U.S. Environmental Protection Agency .Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems . Natural Gas STAR. Environmental Protection Agency. 2006 e . U.S. Environmental Protection Agency. Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems . Natural Gas STAR. Environmental Protection Agency. 2006. f. URS Corporation/University of Texas at Austin. 2011. Natural Gas Industry Methane Emission Factor Improvement Study, Final Report. December 2011. http://www.utexas.edu/research/ceer/GHG/files/FReports/XA_83376101_Final_Report.pdf . g. American Petroleum Institute (API) and America’s Natural Gas Alliance (ANGA). 2012. Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production. Summary and Analysis of API and ANGA Survey Responses. Final Report. September 21, 2012. h The AP I/ANGA study provided information on equipment counts that could augment nationwide emissions calculations. No source emissions information was included. i. ICF International. 2014. Economic Analysis of Methane Emissions Reduction Opportunities in the U .S. Onshore Oil and Natural Gas Industries. Prepared for the Environmental Defense Fund. March 2014. **5.2.2.2 Representative Reciprocating and Centrifugal Compressor** 

**Emissions** The c entrifugal compressor methane emission factors used for processing are based on emission factor data for wet seals and dry seals from a sampling of wet seal and dry seal centrifugal compressor data in the 2012 GHG Inventory . Although we have additional data available on fugitive emission from compressor s tations, including data from the Measurement of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results study published in 2015 33 , the data sets for gathering and boosting facilities had skewed distributions. In th e study data set, 30 percent of gathering facilities contributed 80 percent of the total emissions, and gathering facilities emitted, on average, yi elded higher emission than would be calculated with the factor used in this analy sis. Therefore, f or gatheri ng and boosting station reciprocating compressors, we used the same methane emission factor used in the 2011 NSPS TSD. Emission factors in the

33 Mitchell, Austin L. et al. Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results . Environ. Sci. Technol. 2015, 2119 - 3227.***E.O. 12866 Review

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5 - 7 Compressors Clearstone study 34 , which are expressed in thousand standard cubic feet per cylinder , were multiplied by

the avera ge number of cylinders per gathering and boosting station reciprocating compressor. The volumetric methane emission rate was converted to a mass emission rate using a density of 41.63 pounds of methane per thousand cubic feet. This conversion factor was de veloped assuming that methane is an ideal gas and using the ideal gas law to calculate the density . A summary

of the reciprocating compressor methane emission factor s used for this anal ys is is presented in Table 5 - 2. Once the mass methane emission rate w as calculated, ratios were used to estim ate VOC emissions us ing the methane to VOC pollutant ratios developed in the 2011 Gas Composition M emorandum. The specific ratio that was used to convert methane to VOC i s 0.278 pounds VOC per pound of methane for th e production and proc essing segments . Table 5 - 3 presents a summary of the estimated methane and VOC emissions per reciprocating and centrifugal compressor (in tons per ye ar) for the production and processing segments. **Table 5 -**  **2 .**  **Methane Emission Factors for Reciprocati**  **ng and Centrifugal Compressors 35**  **Oil and Gas Industry**  **Segment Reciprocating Compressors**  **Centrifugal Compressors**

**Methane Emission**  **Factor (scf**  **h**   ** cylinder)** **Average**

**Number of Cylinders**  **Pressurized**

**Factor (% of hour/year**  **Compressor Pressurized)**  **Wet Seal**

**Methane Emission**  **Factor (scf**  **m )**  **Dry Seals**

**Methane Emission**  **Factor (scf**  **m )**  Gathering & Boosting Stations 25.9 a 3.3 79.1% N/A c N/A c Processing 57 b 2.5 89.7% 47.7 d 6 d

a Clearstone Engineering Ltd. Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites. (Draft): 2006. b EPA/GRI. Methane Emissions from the Natural Gas Industry: Volume 8

– Equipment Leaks . Table 4 - 14. c The 1996 EPA/GRI Study Volume 11, does not report any centrifugal compressors in the production or gathering/boosting sectors, therefore no emission factor data were published for those two sectors. d U.S Environmental Protection Agency. Methodology for Estimating CH 4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks1990 - 2012 . Washington, DC. April 2014.

34 Clearstone Engineering Ltd. Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites . (Draft): 2006. 35 National Risk Management Research Laboratory. GRI/EPA Research and Development, Methane Emissions from the Natural Gas Industry . Prepared for the U.S. Department of Energy, Energy Information Administration.EPA 600/R- 96 - 080h. June 1996.***E.O. 12866 Review

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5 - 8 Compressors **Table 5 -**  **3 .**  **Baseline Methane VOC Emission Estimates for Reciprocating and Centrifugal**  **Compressors Industry Segment/Compressor Type**  **Baseline Emission Estimates**  **(tpy) Methane**  **VOC Reciprocating Compressors**  Gathering and Boosting Station s 12.3 3.42 Processing 22 6.12

**Centrifugal Compressors (Wet seals)** Processing 211 58.66

**Centrifugal Compressors (Dry seals)** Processing 26 7.23 

### 5.3 **Available Controls and Regulatory A**  **pproaches 5.3.1**  **Available VOC Emission Control Options** Available controls for controlling VOC emissions from reciprocating and centrifugal compressors are presented in sectio ns 5.3.1.1 and 5.3.1.2 of this c hapter. **5.3.1.1 Reciprocating Compressors**  Potential control options for reducing emissions from reciprocating compressors include control techniques that limit the leaking of natural gas past the piston ro d packing. These options include (1) increasing or specifying the frequency of the replacement of the compressor rod packing, (2) increasing or specifying the frequency of the replacement of the piston rod, and (3) specifying the refitting or realignment o f the piston rod. In addition to these options, there are emerging control techniques where specific anal ys es have not yet been conducted. For example, there may be potential for reducing VOC emission by updating rod packing components made from newer materials which can help improve the life and performance of the rod packing sy stem (economic rod packing replacement) and capturing gas from the reciprocating compressor and routing it back to the compressor engine to be used as fuel. These emerging VOC emiss ions control techniques are discussed briefl y below, along with our evaluation of the frequency of compressor rod packing/piston rod replacement and piston rod refitting and realignment control options.***E.O. 12866 Review

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5 - 9 Compressors We did not evaluate combustion as a control option b ecause, as detailed in the 2011 NSPS TSD, routing of emissions to a control device can cause positive back pressure on the packing, which can cause safety issues due to gas backing up in the distance piece area and engine crankcase in some designs. While c onsidering the option of routing of emissions to a process through a closed vent sy stem under negative pressure, we determined that the negative pressure requirement not only ensures that all the emissions are conveyed to the process, it also avoids the is sue of inducing back pressure on the rod packing and the resultant safety concerns. Although this option can be used in some circumstances, it cannot be applied in every installation. As a result, these options were not further considered under this guidel ine. Frequency

of Rod Packing Replacement For reciprocating compressors, one of the options for reducing VOC emissions is a maintenance task that would increase or specify the frequency

of replacement of the rod packing in order to reduce the leakage of natural gas past the piston rod. Over time the packing rings wear and allow more natural gas to escape around the piston rod. Regular replacement of these rings reduces VOC emissions. Therefore, this control technique is considered to be an available VOC emi ssion control technique for reciprocating compressors. Description As noted previousl y, reciprocating compressor rod packing consists of a series of flexible rings that fit around a shaft to create a seal against leakage. As the rings wear, they allow more compressed natural gas to escape, increasing rod packing emissions. Rod packing emissions ty picall y occur around the rings from slight movement of the rings in the cups as the rod moves, but can also occur through the “nose gasket” around the packing case, between the packing cups, and between the rings and shaft. If the fit between the rod packing rings and rod is too loose, more compressed natural gas will escape. Periodically replacing the packing rings ensures the correct fit is maintained between packing rings and the rod. 36 Control Effectiveness As discussed above, regular replacement of the reciprocating compressor rod packing can reduce the leaking of natural gas across the piston rod. The potential emission reductions for gathering and boosting station s and the processing segment were calculated by comparing the

36 U.S. Environmental Protection Agency . Lessons Learned from Natural Gas STAR Partners. Reducing Methane Emissions from Compressor Rod Packing Systems . Natural Gas STAR Program. 2006.***E.O. 12866 Review

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5 - 10 Compressors average rod packing emissions with the average emissions from newly installed and worn - in rod packing. For the baseline, we assumed that rod packing is replaced every four years. The analy sis uses Equation 1 for estimating gathering and boosting station emission reductions, and Equation 2 for estimating processing segment emission reductions that would result from replacing worn packing with newl y installed packing at a frequency of every 3 years or every 26,000 hours. 37

Where: B G WP 

### R & = Potential methane emission reductions from gathering and boosting station compressors b y replacing worn packing with newly installed packing, in million cubic feet per year (MMcf/ye ar);

B G Existing 

### Comp & = Number of existing gathering and boosting station compressors; E G& B = Methane emission factor for gathering and boosting station compressors, in cubic feet per hour per cylinder ( 25.9 scfh - cylinder); E New =Average emissions from a newl y installed rod packing, assumed to be 11.5 cubic feet per hour per cylinder 38 for this anal ys is; C = Average number of cylinders for gathering and boosting station compressors (i.e., 3.3 ) O = Percent of time during the calendar ye ar the average gathering and boosting station compressor is in the operating and standb y pressurized modes, 79.1 percent pressurized ; 8760 = Number of hours in a year; 10 6 = Number of cubic feet in a million cubic feet.

37 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Tran smission, and Distribution

– Background Technical Support Document for Proposed Standards . July 2011. EPA Document Number EPA - 453/R- 11 - 002. 38 U.S. Environmental Protection Agency . Lessons Learned from Natural Gas STAR Partners. Reducing Methane Emissions f

rom Compressor Rod Packing Systems . Natural Gas STAR Program. 2006. **Equation 1** 

##   6 & & & 

### 10 8760      O C E E Comp R New B G B G Existing B G WP***E.O. 12866 Review

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5 - 11 Compressors **Equation 2** 

##   6 

### 10 8760

     O C E E Comp R New P P Existing P Where: P 

### R = Potential methane emission reductions from processing compressors replacing worn packing to newl y installed packing, in million cubic feet per ye ar (MMcf/year);

P Existing 

### Comp = Number of existing processing compressors; E P = Methane emission factor for processing compressors, in cubic feet per hour per cylinder , 57 scfh - cylinder; E New =Average emissions from a newl y installed rod packing, assumed to be 11.5 cubic feet per hour per cylinder 39 for this anal ys is; C = Average numb er of cylinders for processing compressors (i.e., 2.5); O = Percent of time during the calendar ye ar the average processing compressor is in the operating and standb y pressurized modes, 89.7 percent; 8760 = Number of hours in a year; 10 6 = Number of cubic feet in a million cubic feet. Table 5 - 3 presents a summary of the potential emission reductions for reciprocating compressor rod packing replacement for gathering and boosting station compressors and processing segment compressors based on the percent natural gas reduction calculated from the above equations. The emissions of VOC were estimated using the methane emissions calculated above and the methane - to - VOC - ratio developed for each of the segments in the 2011 Gas Composition Memorandum.

39 U.S. Environmental Protection Agency . Lessons Learned from Natural Gas STAR Partners. Reducing Methane Emissions from Compressor Rod Packing Systems . Natural Gas STAR Program. 2006.***E.O. 12866 Review

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5 - 12 Compressors **Table 5 -**  **4 .**  **Estimated Annual Reciprocating Compressor Emission Reductions from**

**Increasing the Frequency of Rod Packing Replacement ONG**  **Segment Individual Compressor**  **Emission Reductions (tons/compressor**  **- year)**  **Methane VOC**  Gathering and Boosting 6.84 1.9 Processing 17.58 4.89 Cost Impacts Costs for the specified frequency of replacement of reciprocating compressor rod packing documented in the 2011 NSPS TSD were ob tained from a Natural Gas Star lessons l earned document which estimated the cost to replace the packing rings to be $1,712 per cylinder (converted from 2008 dollars to 2012 dollars). It was assumed that rod packing replacement would occur during planned shutdowns and maintenance, and therefore no additional tra vel costs would be incurred for implementing the rod packing replacement program. In addition, no costs were included for monitoring because the rod packing replacement is based on the number of hours that the compressor operates or the period of time sinc e the previous replacement. The 2011 NSPS TSD analy sis assumed that, at baseline, the replacement of rod packing for reciprocating compressors occurs on average every four years based on industry information from the Natural Gas STAR Program. The cost impa cts are based on the replacement frequency of the rod packing every

26,000 hours that the reciprocating compressor operates in the pressurized mode. The 26,000 hour replacement frequency used for the cost impacts in the 2011 NSPS TSD was determined using a weighted average of the annual percentage that the reciprocating compressors are pressurized. The weighted average percentage was calculated to be 98.9 percent. This percentage was multiplied by the total number of hours in 3 ye ars to obtain a value of 2 6,000 hours. Assuming an interest rate of 7 percent, the capital recovery factors (based on replacing the rod packing every 3 years or 26,000 hours) were calculated to be 0.3122 and 0.3490 for gathering and boosting station s and the processing segment, res pectivel y. The capital costs were calculated using the average rod packing cost of $1,712 (converted from $1,620 in***E.O. 12866 Review

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5 - 13 Compressors 2008 dollars to 2012 dollars) and the average number of cylinders per compressor (assumed to be 3.3 cylinders for gathering and boosting compressors and 2.5 cylinders for processing segment compressors). 40 The annual costs were calculated using the capital cost s and the capital recovery factors. Table 5 - 4 presents a summary of the capital and annual costs for gathering and boosting stations and the processing segment. There are monetary

savings associated with the amount of gas saved with reciprocating compressor rod packing replacement. Monetary savings associated with the amount of gas saved with reciprocating compressor rod packing replacement was estimated using a natural gas price of $4.00 per Mcf. 41 Table 5 - 5 presents the annual cost s with savings and cost of control for reciprocating rod packing replacement for gathering and boosting station s and the processing segment. Reciprocating compr essor rod packing replacement prevents the escape of natural gas from the piston rod. In addition to reducing VOC emissions there would be a co - benefit of reducing other emissions (such as methane) as a result of increasing the frequency of rod packing rep lacement. No secondary air pollutants or wastewater should be created, nor energy impacts incurred. **Table 5 -**  **5 .**  **Cost of Control for Reciprocating Compressor Rod Packing Replacement Oil and Gas**  **Segment Capital** 

**Cost s**  **($2012) a**  **Annual Cost s**  **per**

**Compressor ($/compressor**  **- year)**  **VOC Cost of Control ($/ton)**  **Without Savings**  **With**

**Savings Without** 

**Savings With** 

**Savings** Gathering and Boosting $6,848 $2, 153 $ 566 $ 1,132 $ 298 Processing $4,280 $1,631 ($2,443) $334 ($500)

a. 2012 TSD 2008 dollars converted to 2012 dollars using the Federal Reserve Economic Data GDP Price Deflater (5.69 percent)

40 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution

– Background Technical Support Document for Proposed Standards . July 2011. EPA Document Numb er EPA - 453/R- 11 - 002. 41 U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price. Energy Information Administration Natural Gas Navigator . Retrieved online on December 12, 2010 at http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm***E.O. 12866 Review

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5 - 14 Compressors Frequency

of Replacement and/or Realignment/Retrofitting of the Piston Rod Like the packing rings, piston rods on reciprocating compressors also deteriorate. Piston rods, however, wear more slowly than packing rings, having a life of about 10 years. 42 Rods wear “out - of

- round” or taper when poorl y aligned, which affects the fit of packing rings against the shaft (and therefore the ti ghtness of the seal) and the rate of ring wear. An out - of - round shaft not only seals poorl y, allowing more leakage, but also causes uneven wear on the seals, thereb y shortening the life of the piston rod and the packing seal. Replacing or upgrading the rod can reduce reciprocating compressor rod packing emissions. Also, upgrading piston rods by coating them with tungsten carbide or chrome reduces wear over the life of the rod. We assume that operators will choose, at their discretion, when to replace/realign or retrofit the rod as part of regular maintenance procedures and replace the rod when appropriate when the compressor is out of service for other maintenance such as rod packing replacement. Therefore, we did not consider this option any

further. Updat ed Rod Packing Material Although specific analy ses have not been conducted, there may be potential for reducing VOC emission by

updating rod packing components made from newer materials, which can help improve the life and performance of the rod packing s ys tem. One option is to replace the bronze metallic rod packing rings with longer lasting carbon - impregnated Teflon rings. Compressor rods can also be coated with chrome or tungsten carbide to reduce wear and extend the life of the piston rod. 43 Although ch anging the rod packing material has been identified as a potential VOC emission reduction option for reciprocating compressors, there is insufficient information on its emission reduction potential and viability throughout the source category . Economic Rod Packing Replacement Another option facilities can use hat has the potential to reduce costs and emissions is for facilities to use specific financial objectives and monitoring data to determine emis sion levels at which it is cost effective to replace rings and rods. Benefits of calculating and utilizing this “economic replacement threshold” include VOC emission reductions and natural gas cost savings. Using this approach, one Natural Gas STAR partner reportedl y achieved savings of over $233,000 annuall y at 2006 gas prices. An economic replacement threshold approach would also 42 U.S. Environmental Protection Agency . Lessons Learned from Natural Gas STAR Partners. Reducing Methane Emissions from Compressor Rod Packing Systems . Natural Gas STAR Program. 2006. 43 Ibid.***E.O. 12866 Review

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5 - 15 Compressors result in operational benefits, including a longer life for existing equipment, improvements in operating efficiencies, and long - term savings. 44 Gas Recovery

(Routing of Emissions t o a Process) Description Another control option for reciprocating compressors includes control techniques that recover natural gas leaking past the piston rod packing. We are aware of a system that captures the natural gas that would otherwise be vented and routes it back to the compressor engine to be used as fuel. 45 The vent gases are passed through a valve train that includes a demister and then are injected into the engine intake air after the air filter. In general, the technology consists of recoveri ng vented emissions from the rod packing under negative pressure and routing these emissions of otherwise vented gas to the air intake of a reciprocating internal combustion engine that would burn the gas as fuel to augment the normal fuel supply . The syst em’s computerized air/fuel control s ys tem would then adjust the normal fuel supply to accommodate the increased fuel made available from the recovered emissions and thereb y take advantage of the recovered emissions while avoiding an overl y rich fuel mixture. Another method for capturing emissions from reciprocating compressor rod packing vents is to manifold the vent line to a VRU sy stem. The recovered natural gas can then be sold or routed for fuel or other meaningful use onsite. If the natural gas cannot be used productivel y, it can also be sent to a flare sy stem. While flaring may have a higher cost than venting to the atmosphere, this practice can reduce VOC emissions. Subpart OOOO, as well as the 2015 proposed subpart OOOOa, provide a compliance option for reciprocating compressors that allows collecting emissions from the rod packing using a rod packing emissions collection sy stem which operates under negative pressure and routing the rod packing emissions to a process through a closed vent sy stem. Both of the above s ys tems, if installed using a closed vent sy stem meeting the subpart OOOO and subpart OOOOa requirements, could potentially be used for this compliance option.

44 U.S. Environmental Protection Agency. Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR. Environmental Protection Agency. 2006. 45 REM Technology Inc. and Targa Resources. Reducing Methane and VOC Emissions . P resentation for the 2012 Natural Gas STAR Annual Implementation Workshop.***E.O. 12866 Review

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5 - 16 Compressors Control Effectiveness One estimate obtained b y the EPA states that the gas recovery s ys tem can result in the elimination of over 99 percent of VOC and methane emissions that would otherwise occur from the venting of the emissions from the compressor rod packing. 46 The emissions that would have been vented are combusted in the comp ressor engine to generate power. If the facility

is able to route rod packing vents to a VRU sy stem, it is possible to recover approximately

95 - 100 percent of emissions. I f the gas is routed to a flare, approximately 95% of the methane and VOCs are reduce d. Cost Impacts One estimate reported that the cost per engine would be approximately $12,000 (does not include installation costs). Some costs would be mitigated b y fuel gas savings, as using the captured gas to displace some of the purchased fuel would require less fuel to be purchased in order to run the compressor engine. The fuel cost saving based on a 4 throw compressor with moderate leak rate would be an estimated $6,500 per year. 47 This technique is discussed further in the Natural Gas STAR PRO Fact Sheet titled “Install Automated Air/Fuel Ratio Controls”. 48 This document reported an average fuel gas savings of 78 Mcf/day per engine with the gas recovery s ys tem installed. Based on our review of information on this technology , we conclude that this tec hnology

has merit and would provide equivalent or better emissions reductions that increasing the replacement of rod packing from every 4 years to every

3 years since the emissions would be captured under negative pressure, allowing all emissions to be routed to the engine. It is our understanding that this technology may not be applicable to every compressor installation and situation. For a VRU, assuming the proper equipment is already available at the facility , capturing the rod packing emissions would require minimal costs. The investment would only need to include the cost of piping and installation. While we have not obtained a cost estimate specificall y for routing rod packing vents to a VRU, this process has been studied for dehydrators and would be similar for rod packing sy stems. According to the Natural Gas STAR

46 REM Technology Inc., et al. Profitable Use of Vented Emission in Oil & Gas Production . Prepared with support from the Climate Change and Emissions Management Corporation (CCEMC). 2 013. 47 REM Technology Inc. Presentation to the U.S. Environmental Protection Agency on December 1, 2011. EPA Docket ID No. EPA - HQ - OAR - 2010 - 0505. 48 U.S. Environmental Protection Agency. 2011c. Gas STAR PRO No. 104. Install Automated Air/Fuel Ratio Controls . 2011. Available at: http://epa.gov/gasstar/documents/auto - air - fuel - ratio.pdf.***E.O. 12866 Review

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5 - 17 Compressors PRO Fact Sheet titled “Pipe Glycol Deh ydrator to Vapor Recovery Unit,” 49 the cost for planning and installing additional piping is approximately $2,000. Routing to a VRU also provides additi onal incentive as there is a value associated with recovered gas. However, the installation of a VRU to only

capture rod packing emissions may not be economically

viable if an additional compressor s ys tem is required. If the VRU is already present at the f

acility , the incremental cost to capture the rod packing vent gas can be recovered from the value of the additional captured natural gas. Although gas recovery

has been identified as a potential VOC emission reduction option for reciprocating compressors, there is insufficient information on its availability as a reasonabl y available control option for reducing reciprocating compressor VOC emissions. However, we recommend that regulatory agencies consider this technology as a compliance option when implementing the RACT recommendations presented below. **5.3.1.2 Centrifugal Compressors Equipped with Wet Seals**  Potential control options to reduce emissions from centrifugal compressors equipped with wet seals include control techniques that limit the leaking of n atural gas across the rotating shaft, and capture and destruction of the emissions by routing emissions to a process (e.g., a compressor or fuel gas s ystem) or to a combustion device (discussed in detail in sections 4.3.1.2 of Chapter 4). We evaluate below three available control options: (1) converting wet seals to dry seals; (2) routing emissions to a fuel gas s ys tem or compressor (process); and (3) routing emissions to a combustion device. Converting Wet Seals to Dry Seals Description We evaluated the use of centrifugal compressor dry seals as an available VOC control option for wet seal centrifugal compressors. As noted in section 5.2.1 of this c hapter, the VOC emission profile from the use of dry seals is considerabl y less than from the use of wet seals. Replacing wet seals with dry seals can therefore substantially reduce VOC emissions across the rotating shaft compared to wet seals, while simultaneously reducing operating costs and enhancing compressor efficiency compared to wet seal s. During normal operation, dry seals leak

49 U.S. Environmental Protection Agency. Gas STAR PRO No. 203. Pipe Glycol Dehydrator to Vapor Recovery Unit . 2011. Available at: http://epa.gov/gasstar/documents/pipeglycoldehydratortovru.pdf.***E.O. 12866 Review

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5 - 18 Compressors at a rate of 6 scfm methane per compressor. 50 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 f

rom the seal oil before the oil is recirculated is usuall y vented to the atmosphere, bringing the total leakage rate for tandem wet seals to 47.7 scfm methane per compressor. 51 , 52 It is not practical or feasible in all situations , however, to retrofit an ex isting wet seal compressor with a dry

seal compressor. We have received information that indicates that the conversion process requires a significant period of time to complete and the compressor would need to be out of commission for the conversion period . Control Effectiveness The emissions reduction that would occur b y replacing wet seal compressors with a dry seal compressor was calculated by subtracting the dry

seal emissions from the emissions from a centrifugal compressor equipped with wet seals. We used the centrifugal compressor emission factors in T able 5 - 2 and e stimated that VOC emissions would be reduced by 16.7 tpy per compressor. Cost Impacts The Natural Gas STAR Program estimated the cost of retrofitting dry seals on a centrifugal compressor equipped with wet seals to be $324,000 ($342,439 in 2012 dollars) for a two - seal dry

seal system, which includes the cost of both seals and the dry gas co nditioning, monitoring, control console and installation. 53 The annual costs were calculated as the capital recovery of this capital cost s assuming a 20 - ye ar equipment life and 7 percent interest which came to $32,324 per compressor. The Natural Gas STAR Program estimated that the annual operation and maintenance savings from the installation of dry seal compressor is $88,300 ($93,325 in 2012 dollars) in comparison to a wet seal compressor. In addition, the installation of dry seals reduces natural gas emiss ions by 10,721 Mscf/y

r 54 which would produce a natural gas savings of $42,883 per year assuming a natural gas price of $4/Mcf . A summary

of the capital and annual costs for replacing a wet seal compressor with a dry seal compressor is presented in

50 U.S. Environmental Protection Agency. Lessons Learned Document. Replacing Wet Seals with Dry Seals in Centrifugal Compressors . October 2006. Available at http://epa.gov/gass tar/documents/ll_wetseals.pdf . 51 U.S. Environmental Protection Agency, et al. Methane’s Role in Promoting Sustainable Development in the Oil and Natural Gas Industry . World Gas Conference 10/2009. Available at: http://www.epa.gov/gasstar/documents/best_paper_award.pdf 52 U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions from Natural Gas Systems . Inventory of U.S. Greenhouse Gas Emission and Sinks: 1 990 - 2012 . Washington, DC. Annex 3. Table A 129.***E.O. 12866 Review

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5 - 19 Compressors Table 5 - 5 along with the VOC cost of control. As noted above, we have received information that indicates that the conversion process requires a significant period of time to complete and the compressor would need to be out of commission during the conversion perio d. Because of this, a facility

may have to provide a temporary compressor in the interim that would add additional cost the cost estimates we present in Table 5 - 6 . **Table 5 -**  **6 .**  **Cost of Reductions from Replacing a Wet Seal Centrifugal Compressor with a**  **Dry Seal Centrifugal Compressor Oil & Natural Gas**  **Segment Capital** 

**Cost s**  **($ 2012**  **) Annual Cost**  **s Per Compressor** 

**($/c ompressor** **- year)**  **VOC Cost of Control ($/ton)**  **Without S**  **avings a**  **W ith O&M**  **and**

**Natural Gas S**  **avings b**  **Without**

**S avings**  **W ith O&M**  **and**

**Natural Gas Savings**  Processing $ 342,439 $32,324 ($103,884) $1,931 ( $6,205 ) a Includes only the annualized capital cost s of the retrofit of the dry seal system (20 years, 7% interest). b Includes the annualized capital cost s , annual O& M savings and annual natural gas savings. Routing Emissions to a Compressor or Fuel Gas System (Process) Description One option for reducing VOC emissions from the compressor wet seal fluid degassing sy stem is to route the captured emissions back to the c ompressor suction or fuel sy stem or other beneficial use (referred to collectively as routing to a process). Routing to a process would entail routing emissions via a closed vent sy stem to any enclosed portion of a process unit (e.g., compressor or fuel ga s s ystem) where the emissions are predominantly recycled, consumed in the same manner as a material that fulfills the same function in the process, transformed b y chemical reaction into materials that are not regulated materials, incorporated into a produc t, or recovered. Emissions that are routed to a process are assumed to result in the same or greater emissions reductions as would have been achieved had the emissions been routed through a closed vent s ys tem to a combustion device. Table 5 - 7 presents a summary of the estimated emission reductions from routing emissions from the wet seal fluid degassing s ys tem to a process. For purposes of this analy sis, we assume that routing VOC emissions from a wet seal

53 U.S. Environmental Protection Agency. Lessons Learned Document. Replacing Wet Seals with Dry Seals in Centrifugal Compressors . October 2006. Available at http://epa.gov/gasstar/documents/ll_wetseals.pdf . 54 The natural gas savings was calculated by using the 16.7 tpy VOC reduction and dividing by the VOC/methane weight ratio of 0.278 to determine the amount of methane reduction that would be reduced (60.1 tpy). The methane emission reductions were converted to volumetric natural gas reductions assuming a natural gas density of 0.02082 tons/Mcf and a 82.9 volume percent conversion factor of methane to natural gas.***E.O. 12866 Review

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5 - 20 Compressors fluid degassing s ys tem to a process reduces VOC emissions greater than or equal to a combustion device. **Table 5 -**  **7 .**  **Estimated Annual Centrifugal Compressor VOC Emission Redu ctions for** 

**Routing Wet Seal Fluid Degassing System to a Process**  **55 ,**  **56 Oil & Gas Segment**  **Individual Compressor VOC Emission Reductions**  **(tons/compressor -** **year)** Processing > 18.10 Cost Impacts The capital costs of a s ys tem to route the seal oil degassing s ys tem to a process is estimated to be $23,252, 57 converting to 2012 dollars using the Federal Reserve Economic Data GDP Price Deflater (Change in GDP: Implicit Price Deflator from 2008 to 2012 (5.69 percent)) . 58 The estimated costs includes an intermediate pressure degassing drum, new piping, gas demister/filter, and a pressure regulator for the fuel line. The annual costs were estimated to be $2,553 assuming a 15 year equipment life at 7 percent interest. Potential natural gas savings for this option were estimated to be 12 Mcf/y r and assumes that 95 percent of the 47.7 scfm methane emissions are controlled, an annual operating factor of 43.6 percent, and the 82.9 volume percent conversion factor of methane to natural gas. Assuming a natural gas savings of $4/Mcf, the natural gas savings equates to approx imately $47,551 per ye ar. Table 5 - 8 presents a summary of the cost of control for routing emissions to a process. **Table 5 -**  **8 .**  **VOC Cost of Control for Routing Wet Seal Fluid**  **Degassing System to a Process a** 

55 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New S

ource Performance Standards . April 2012. EPA Docket Number EPA - HQ - OAR - 2010 - 0505 - 4550. 56 Ibid. 57 Ibid. 58 U.S. Bureau of Economic Analysis. Gross Domestic Product: Implicit Price Deflator (GDPDEF] , retrieved from FRED, Federal Reserve Bank of St. Louis. https://research.stlouisfed.org/fred2/series/GDPDEF/ March, 26, 2015.***E.O. 12866 Review

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5 - 21 Compressors **Oil and Gas Segment**  **Capital**

**Cost s**  **($2012) a**  **Annual Cost s**  **per**

**Compressor ($/compressor**  **- year)**  **VOC Cost of Control ($/ton)**  **Without Savings**  **With**

**Savings Without** 

**Savings With** 

**Savings** Processing $23,252 $2,553 ($47,553) $141 ($2,621) NA = Not Applicable a. 2012 TSD 2008 dollars converted to 2012 dollars using the Federal Reserve Economic Data GDP Price Deflater (Change in GDP: Implicit Price Deflator from 2008 to 2012 (5.69%)). 59 Routing Emissions to a Combustion Device Description Combustion devices are co mmonly used in the ONG production source category to combust VOC emission streams. A combustion device generall y achieves 95 percent reduction of VOC when operated according to the manufacturer instructions. Ty pical combustion devices used in the ONG produ ction source category to control VOC emissions are discussed in greate r detail in section 4.3.1.2 of c hapter 4 of this document. For this anal ys is, we assumed that the entrained natural gas from the seal oil that is removed in the degassing process would be directed to a combustion device that achieves a 95 percent reduction of VOC. The wet seal emissions in Table 5 - 2 were used along with the control efficiency to calculate the emissions reductions. Table 5 - 9 presents a summary of the estimated emission re ductions from routing emissions from the wet seal to a combustion device.

59 U.S. Bureau of Economic Analysis, Gross Domestic Product: Implicit Price Deflator (GDPDEF], retrieved from FRED, Federa l Reserve Bank of St. Louis. https://research.stlouisfed.org/fred2/series/GDPDEF/ March, 26, 2015.***E.O. 12866 Review

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5 - 22 Compressors **Table 5 -**  **9 .**  **Estimated Annual VOC Emission Red uctions for Routing Wet Seal Fluid** 

**Degassing System to a Combustion Device 60**  **, Oil & Gas Segment**  **Individual Compressor VOC Emission Reductions**  **(tons/compressor -** **year)** Processing 18.1 Cost Impacts Routing the captured gas from the centrifugal compressor wet seal degassing s ys tem to an existing combustion device or installing a new combustion device has associated capital costs and operating costs. The capital and annual cost s of the combustion device (an encl osed flare for the anal ys is) were calculated using the methodology in the EPA Control Cost Manual. 61 However, Control Cost Manual guidelines spec ify that 630 operating labor hours per ye ar for a combustion device, which we believe is unreasonable because many of these sites are unmanned and would most likely be operated remotely . Therefore, we assumed that the operating labor would be more similar to that estimated for a condenser in the Control Cost Manual, which is 130 hours per ye ar. The heat content of the gas stream was calculated using information from the 2011 Gas Composition Memorandum. T able 5 - 10 presents a summary of the capital and annual costs for wet seals routed to a flare, as well as the VOC cost of control. There is no cost savings estimated for this option because the reco vered natural gas is combusted.

60 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Perform ance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New Source Performance Standards . April 2012. EPA Docket Number EPA - HQ - OAR - 2010 - 0505 - 4550. 61 EPA Air Pollution Control Cost Manual - Sixth Edition, (EPA 452/B - 02 - 001).***E.O. 12866 Review

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5 - 23 Compressors **Table 5 -**  **10 .**  **Cost of Control for Routing Wet Seal**  **Fluid Degassing System to a Combustion**  **Device Industry**  **Segment Capital Cost**  **s**

**($) Annual Cost**  **s per** 

**Compressor ($/compressor**  **- year)**  **VOC Cost of Control**  **New CD ($/ton)**  **VOC Cost of**

**Control Existing CD**  **($/ton) New CD**  **Existing**

**CD New CD**  **Existing CD** Processing $71,783 $23,252 $114,146 $3,311 $6,292 $183 CD = Control Device **5.3.2 Existing Federal, State and Local Regulations**  **5.3.2.1 Federal Regulations that Specifically Require Control of VOC** 

**Emissions** Under the 2012 NSPS, reciprocating compressors are required to limit VOC emissions by replacing the rod packing after 26,000 hours of operation or 36 months since the previous rod packing replacement. Alternativel y, an owner or operator is allowed to route rod packing emissions to a process through a closed vent sy stem under negative pressure. For centrifugal compressors in the processing segment, the 2012 NSPS requires that VOC emissions be reduced from each centrifugal compressor wet seal fluid degassing sy stem by 95 percent. **5.3.2.2 State and Local Regulations**  **that Specifically Require Control of VOC**

**Emissions** States may

have permitting restrictions on VOC emissions that may apply to an emissions source as a result of an NSR NA or PS D permit (e.g., on a case - by- case basis) requirements based on air quality maintenance or improvement goals of an area. Permits specify what construction is allowed, what emission limits must be met, and often how the source must be operated. To assure that source s follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements. Montana requires ONG well facilities to control emissions from the time the well is completed until the source is registered or permitted. Each piece of oil or natural gas well facility equipment, with VOC vapors of 200 Btu/scf or more with a PTE greater than 15 tpy , is required to (1) capture and route emissions to a natural gas pipeline, (2) route to a smokeless combustion device equipped with an electronic ignition device or a continuous burning pilot system meeting***E.O. 12866 Review

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5 - 24 Compressors the requirements of 40 CFR 60.18 and operating at 95 percent or greater control efficiency , or (3) route to air pollution control equipment with equal or greater control efficiency than a smokeless combustion device. This includes the control of emissions from compressor engines used for transmission of natural gas (Registration of Air Contaminant Sources, Rule 17.8.1711 Oil or Gas Well Facilities Emission Control Requirements). Colo rado (Regulation 7, XVII.B.3.b and c) requires that uncontrolled actual hydrocarbon emissions from wet seal fluid degassing s ys tems on wet seal centrifugal compressors be controlled by

at least 95 percent, unless the centrifugal compressor is subject to 40 CFR part 60, subpart OOOO. Additionally , Regulation 7 requires that rod packing on any reciprocation compressor located at a natural gas compressor station be replaced every 26,000 hours of operation or every

36 months, unless the reciprocating compressor is subject to 40 CFR part 60, subpart OOOO. 

### 5.4 **Recommended RACT Level of Control**  For reciprocating compressors, there are federal regulations and one state that requires the periodic replacement of reciprocating compressor packing. These regulations req uire the replacement of reciprocating compressor rod packing every 3 years or after 26,000 hours of operation. The NSPS also provides the alternative of routing rod packing emissions to a process via a closed vent s ys tem under negative pressure. The cost of control for requiring the replacement of reciprocating packing at this frequency was estimated to be $1,132 per ton of VOC reduced without savings and $298 per ton of VOC reduced considering savings for gathering and boosting station compressors , and about $334 per ton of VOC reduced without savings and an overall net savings per ton of VOC reduced for the processing segment considering savings. Based on the emission reductions, costs (considering gas savings) and existing and currently implemented regulations that require the replacement of the reciprocating compressor packing every 36 months or every

26,000 hours, we recommend this control option as RACT for reciprocating compressors at gathering and boosting stations and compressors at processing segments. We also recommend that regulatory agencies provide operators the compliance alternative of routing rod packing emissions to a process via a closed vent s ys tem under negative pressure. Similarly, for centrifugal compressors, there are already federal , state and local regulations that require the capture and 95 percent control of emissions from wet seal fluid***E.O. 12866 Review

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5 - 25 Compressors degassing s ys tems from centrifugal compressors. For the processing segment, we assume that there is already and existing combustion device on - sit e, therefore, we believe that the estimated cost of control is about $183 per ton of VOC reduced for facilities to route emissions to the existing combustion device, or about $141 per ton of VOC for facilities to route the captured emissions back to the co mpressor or fuel line. A cknowledging that the replacement of wet seals with dry seals and routing to a process may not be technicall y feasible or practical options for some centrifugal compressors, our recommended RACT is to require 95 percent control of e missions from the wet seal degassing s ys tem, which can be achieved by using a closed vent sy stem and routing emissions to a combustor or routing the emissions back to the compressor or fuel line (routing to the process), in addition two replacement of wet seals with dry seals and routing to a process. In summary , we recommend the following as RACT for compressors: 1) RACT for Reciprocating Compressors: We recommend that each reciprocating compressor reduce VOC emissions by replacing the rod packing after 26,00 0 hours of operation or 36 months since the last rod packing replacement. We also recommend that an alternative be provided to allow routing of rod packing emissions to a process via a closed vent s ys tem under negative pressure in lieu of the specified rod packing replacement periods. 2) RACT for Centrifugal Compressors: We recommend that each centrifugal compressor using wet seals reduce VOC emissions from each wet seal fluid gassing s ys tem by reducing VOC emissions by 95 percent. 

### 5.5 **Factors to Consider in Developing**  **Compressor Compliance**  **Procedures 5.5.1**  **Reciprocating Compressor Compliance Recommendations** In order to ensure and demonstrate compliance with the recommended RACT for reciprocating compressors, we recommend that regulatory agencies require facilities to maintain a record of the date of the most recent reciprocating compressor rod packing replace ment, monitor and keep records of the number of hours of operation and/or track the number of months since the last rod packing replacement for each reciprocating compressor (to meet the requirement that the packing is changed out before the total number o f hours of operation***E.O. 12866 Review

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5 - 26 Compressors reaches 26,000 hours or the number of months since the most recent rod packing replacement reaches 36 months) and maintain records of instances where the reciprocating compressor was not operated in compliance with RACT. This may requi re the installation of an operating hours meter on the engine to track the number of hours of operation. We also recommend that regulatory

agencies require annual reports of the cumulative hours of operation or number of months since packing replacement fo r each reciprocating compressor and instances when there were deviations where the reciprocating compressor was not operated in compliance with the recommended RACT. For applications in which operators choose to opt for the alternative of routing of rod packing emissions to a process via a closed vent sy stem under negative pressure, we recommend that regulatory

agencies require facilities to maintain records of the date of installation of a rod packing emissions collection system and closed vent sy stem an d maintain records of instances of deviations in cases where the reciprocating compressor was not operated in compliance with requirements. We also recommend that regulatory agencies require annual reports for each reciprocating compressor complying with this option indicating when there were deviations where the reciprocating compressor was not operated in compliance with the recommended RACT. We include closed vent sy stem design and compliance measure recommendations in section 5.5.4 of this c hapter. The Appendix to this document presents example model rule language that incorporates compliance elements recommended in this section that states may choose to use in whole or in part. **5.5.2 Centrifugal Compressor Equipped with a Wet Seal Recommendations**  In ord er to ensure that VOC emissions are reduced by at least 95 percent (the recommended RACT level of control) from a centrifugal compressor equipped with wet seals when using a control device or other control measure (such as routing to a process), the centri fugal compressor should be equipped with a cover that is connected through a closed vent sy stem that routes emissions to the control device (or process) that meets the RACT level of control. Recommended cover and closed vent s ys tem design and operation measures are specified in sections 5.5.3 and 5.5.4. Recommended control device operation and monitoring provisions for specified controls to assure compliance are presented in section 5.5.5.***E.O. 12866 Review

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5 - 27 Compressors The Appendix o f this document presents example model rule language that incorporates compliance elements recommended in this section that states may choose to use in whole or in part. **5.5.3 Recommendations for Cover Design**  The cover and all openings on the cover (e.g., access hatches, sampling ports, pressure relief valves and gauge wells) should form a continuous impermeable barrier over the entire surface area of the liquid in the wet seal fluid degassing s ys tem. Each cover opening should be secured in a closed, sealed position (gasket lid or cap) whenever material is in the unit except when it is necessary

to open as follows: 1) To add material to or remove material from the unit (including openings necessary to equalize or balance the internal pressure of the unit follow ing changes in the level of material in the unit); 2) To inspect or sample the material in the unit; 3) To inspect, maintain, repair, or replace equipment located in the unit; or 4) To vent liquids, gases or fumes from the unit through a closed - vent sy stem design ed and operated in accordance specified control device requirements (see section 5.5.5) or to a process. It is recommended that regulatory agencies require olfactory , visual and auditory inspections of covers for defects that could result in air emissions on a monthly basis. We recommend regulatory

agencies require that any detected defects be repaired as soon as technicall y feasible to minimize emissions (and prior to the end of the next shutdown). **5.5.4 Recommendations for Closed Vent Sy** **stems** The closed vent s ys tem should be designed and operated with no detectable emissions (which can be monitored by monthly olfactory , visual and auditory inspections) and should be operating at least 95 percent of the year. We recommend regulatory agencies require that any detected defects be repaired as soon as technicall y feasible to minimize emissions (and prior to the end of the next shutdown). With the exception of low leg drains, high point bleeds, anal yz er vent, open - ended valves and safety devices, if the closed vent s ys tem contains one or more b ypass devices that could be used to divert all or a portion of the gases, vapors, or fumes from entering the control device or to a process, regulatory

agencies should require that owners or operators either:***E.O. 12866 Review

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5 - 28 Compressors 1) Install, calibrate, maintain and operate a flow indicator at the inlet to the b ypass device that could divert the stream away from the control device or process to the atmosphere that sounds an audible and visual alarm, or, initiates notification via remote alarm to th e nearest field office, when the by pass device is open such that the stream is being, or could be, diverted away

from the control device or process to the atmosphere; or 2) Secure the b yp ass device valve installed at the inlet to the by pass device in the non diverting position using a car- seal or a lock - and - key ty pe configuration. We recommend requiring by

pass devices to be equipped with flow indicators that sound an alarm when the stream is diverted away from the control device or process to the atmosphere and that records be maintained of times when the alarm sounds. **5.5.5 Recommendations for Control Device Operation and Monitoring**  If a control device is used to comply with the recommended 95 percent VOC emission reduction RACT level of control, we advise that the device be required to operate at all times when gases, vapors, and fumes are vented from the wet seal fluid degassing s ys tem through the closed vent s ys tem to the control device. The following paragraphs present select emissions control options an d suggested operation and monitoring requirements, as appropriate to assure compliance with the recommended RACT level of control. Enclosed Combustion Devices If an enclosed combustion device (e.g . , thermal vapor incinerator, catal ytic vapor incinerator, b oiler, or process heater) is used to meet the 95 percent VOC emission reduction RACT level of control, it should be designed to reduce the mass content of VOC emissions by 95 percent or greater; and (1) maintained in a leak free condition, (2) installed an d operated with a continuous burning pilot flame, and (3) operated with no visible emissions. We recommend that the visible emissions test (using section 11 of EPA Method 22, 40 CFR part 60, appendix A - 7) be performed at least once every calendar month. I f a combustion device fails the visible emissions test, sources should be required to follow manufacturer’s repair instructions, if available, or best combustion engineering practice as outlined in the unit inspection and maintenance plan, to return the unit to compliant operation. We recommend all inspection, repair and maintenance activities for each unit be recorded in a maintenance and repair log that can be made available for inspection. Following return to operation from***E.O. 12866 Review

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5 - 29 Compressors maintenance or repair activity, each device should be required to pass a Method 22, 40 CFR part 60, appendix A - 7 visual emissions test . We recommend regulatory agencies require that sources meeting the 95 percent VOC emission reduction RACT level of control b y routing emissions to a c ombustion device conduct performance tests and/or design anal ys es that demonstrate that the combustion device being used meets the required 95 percent VOC emission reduction RACT level of control (see section F of the Appendix to this document for performance testing procedures for control devices that we recommend be used to demonstrate performance requirements). Routing to a Process Routing to a process would entail routing emissions via a closed vent s ys tem to any enclosed portion of a process unit where the emissions are predominantl y rec ycled, consumed in the same manner as a material that fulfills the same function in the process, transformed b y chemical reaction into materials that are not regulated materials, incorporated into a product, or recovered . VRUs and flow lines that “route emissions to a process” would be considered part of the process and would not be considered control devices that are subject to standards, but the closed vent design, operation and monitoring requirements specified in sect ions 5.5.3 and 5.5.4 would apply .***E.O. 12866 Review

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6 - 1 Pneumatic Controllers 

### 6.0 **PNEUM AT**  **IC CONTROLLERS** The ONG production industry uses a variety

of process control devices to operate valves that regulate pressure, flow, temperature, and liquid levels. Most instrumentation and control equipment falls into one of three categories: (1) pneumatic; (2) electrical; or (3) mechanical. Of these, only

pneumatic devices are direct sources of air emissions. Pneumatic controllers are pneumatic devices used throughout the ONG production industry as part of the instrumentation to control the position of valves and may be actuat ed using pressurized natural gas (natural gas driven) or may

be actuated by

another means such as a pressurized gas other than natural gas, solar , or electric. This chapter provides a description of pneumatic controllers that are used in the ONG source cat egory , including their function and associated emissions. This chapter also provides control techniques used to reduce VOC emissions from these pneumatic controllers, along with costs and emission reductions. Finall y, this chapter provides a discussion of our recommended RACT and the associated VOC emission reductions and cost impacts for pneumatic controllers. 

### 6.1 **Ap plicability**  For the purposes of this guideline , a pneumatic controller is an automated instrument used to maintain a process condition such as liquid level, pressure, delta - pressure and temperature. The emissions and emission controls discussed herein would apply to natural - gas driven pneumatic controllers in the ONG source category located from the wellhead to a natural gas processing plant ( including the natural gas pro cessing plant) or from the wellhead to the point of custody

transfer to an oil pipeline . Segments beyond the processing segment were not evaluated in this guideline because the gas is predominantly methane in those segments and VOC emissions would be very low.***E.O. 12866 Review

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6 - 2 Pneumatic Controllers 

### 6.2 **Process Description and Emission Sources 6.2.1**  **Process Description 62**  Natural gas - driven pneumatic controllers come in a variety of designs for a variety of uses. For the purposes of this guideline, they are characterized primaril y b y their emissions characteristics: 1) Continuous bleed pneumatic controllers are used to modulate flow, liquid level, or pressure, and gas is vented continuously at a rate that may

vary over time . Continuous bleed controllers are further subdivided into two ty pes based on their bleed rate: a. Low bleed, having a bleed rate of less than or equal to 6 s tandard cubic feet per hour (scfh). b. High bleed, having a bleed rate of greater than 6 scfh. 2) Intermittent bleed or snap acting pneumatic controllers release gas only when they

open or close a valve or as they throttle the gas flow. 3) Zero bleed pneumatic co ntrollers do not bleed natural gas to the atmosphere. These natural gas - driven pneumatic controllers are self - contained devices that release gas to a downstream pipeline instead of to the atmosphere. Pneumatic controllers often make use of available high - pressure natural gas to operate valves. The suppl y gas pressure is modulated b y a process condition, and then flows to the valve controller where the signal is compared with the process set - point to adjust gas pressure in the valve actuator. In these natural gas - driven pneumatic controllers, natural gas may be released intermittently

with every

actuation of the valve. In other designs, natural gas may be released continuously

from the valve control pilot. The rate at which the continuous release occurs is referred to as the bleed rate. Bleed rates are dependent on the design and operating characteristics of the device. Similar designs will have similar steady- state rates when operated under similar conditions. For purposes of this guideline , we assume that s elf - contained devices that release natural gas to a downstream pipeline instead of to the atmosphere have no emissions. Furthermore, it is recognized that “closed loop” s ystems are applicable onl y in instances with

62 U.S. Environmental Protection Agency. Lessons Learned: Options for Reducing Methane Emissions From Pneumatic Devices in the Natural Gas Industry . Office of Air and Radiation: Natural Gas STAR Progr am . Washington, DC. February 2004***E.O. 12866 Review

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6 - 3 Pneumatic Controllers very low pressure 63 and may

not be suitabl e to replace many applications of continuous or intermittent bleed pneumatic devices. Therefore, this guideline does not address these selfcontained devices further. Intermittent bleed 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 bleed device is dependent on the amount of natural gas vented per actuation and how often it is actuated. Continuous bleed devices also vent an additional volume of gas during actuation, in addition to the device’s continuous bleed stream. Since actuation emissions serve the controller’s functional purpose and can be highly variable, the emissions characterized for high bleed and low bleed devices presented here account for onl y the continuous flow of emissions (i.e., bleed rate) and do not include emissions directly resulting from actuation. For most applications (but not all), intermittent bleed controllers serve functionall y different purposes than continuous bleed devices. Therefore, this guideline does not address intermittent controller devices further. As previously

indicated, not all pneumatic controllers are natural gas - driven . At sites with a continuous and reliable source of electricity , controllers can be actuated by an instrument air sy stem that uses compressed air instead of natural gas. These sites may also use mechanical or electrically

powered pneumatic controllers. In some instances, solar - powered controllers may be feasible. Because these devices are not natural gas - driven , they do not directly

release natural gas or VOC. However, electrically powered s ys tems have energy impacts, with associated secondary impacts related to generation of the electrical power required to drive the instrument air compressor s ys tem. These guidelines assume that natural gas processing plants are the onl y facilities in the ONG source category that are likely

to have electrical service sufficient to power an instrument air s ys tem, and that most existing natural gas processing plants use instrument air instead of natural gas - driven devices. 64 **6.2.2 Emissions Data**  **6.2.2.1 Summary of Major Studies and Emissions**  In the evaluation of the emissions from pneumatic controllers and the potential options available to reduce these emissions, numerous studies were consulted. Table 6 - 1 lists these 63 Memorandum to Bruce Moore, U.S. Environmental Protection Agency, form Denise Grubert, EC/R Incorporated. Meeting Minutes from EPA Meeting with the American Petroleum Institute (API) . October 2011. 64 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic Devices . Prepared for GRI and EPA. EPA - 600/R/ - 96 - 080k. June 1996.***E.O. 12866 Review

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6 - 4 Pneumatic Controllers references with an indication of the ty pe of relevant information contained in each reference. In addition to these sources, we evaluated the peer reviewer and public comments received on the EPA’s white paper, “Oil and Natural Gas Sector Pneumatic Devices.” 65 **Table 6 -**  **1 . Major Studies Reviewed for Consideration of Emissions and Activity Data**  **Re port Name**  **Affiliation Year of**  **Report Activity** 

**Factors Emissions** 

**Data Control** 

**Options** Greenhouse Gas Reporting Program (Annual Reporting; Current Data Available for 2011 - 2013) a EPA 2014 Facility - Level X X Inventory of Greenhouse Gas Emissions and Sinks: 1990 - 2012 b EPA 2014 Nationwide/ Regional X Methane Emissions from the Natural Gas Industryc Gas Research Institute ( GRI) /EPA 1996 Nationwide X Methane Emissions from the Petroleum Industryd GRI/EPA 1996 Nationwide X Methane Emissions from the U.S. Oil Industrye EPA 1999 Nationwide X Oil and Gas Emission Inventories for Western States f WRAP 2005 Regional X Natural Gas STAR Programg EPA 2000 - 2010 Voluntary X X Measurements of Methane Emissions from Natural Gas Production Sites in the United States 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 Air Pollutant Emissions from the Development, Carnegie Mellon University 2014 Regional (Marcellus Shale) X

65 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Pneumatic Devices . Report for Oil and Natural Gas Sector Pneumatic Devices Review Panel. Office of Air Quality Planning and Standards (OAQPS). April 2014. Available at http://www.epa.gov/airquality/oilandgas/2014papers/***E.O. 12866 Review

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6 - 5 Pneumatic Controllers **Re port Name**  **Affiliation Year of**  **Report Activity** 

**Factors Emissions** 

**Data Control** 

**Options** Production, and Processing of Marcellus Shale Natural Gas

j Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries k ICF

International 2014 Nationwide X X

a. U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: Background Technical Support Document. Climate Change Division. Washington, DC. b U.S Environmental Protection Agency. Methodology for Estimating CH 4 and CO 2 Emissions from Natural Gas Systems. Greenhouse Gas Inventory: Emission and Sinks 1990 - 2012. Washington, DC. And U.S Environmental Protection Agency. Methodology for Estimating CH 4 and CO 2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 1990 - 2012. Washington, DC. c. Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical Report. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA - 600/R - 96 - 080b. June 1996, Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 3: General Methodology. Prepared for the Gas Research Institute and Environmental Protection Agency. EP A - 600/R - 96 - 080c. June 1996, Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 5: Activity Factors. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA - 600/R- 96 - 080e. June 1996, and Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic Devices. Prepared for the Gas Research Institute and Environmental Protection Agency. 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. Environmental Protection Agency, June 14, 1996. e. ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry. Prepared for the U.S. Environmental Protection Agency. 1999. f. ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States. Prepared for Western Governor s Association. December 27, 2005. g . U.S. Environmental Protection Agency. Lessons Learned: Options for Reducing Methane Emissions From Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas Star. Washington, DC. February 2004. h. Memorandum to Bruce Moore from Heather Brown. Gas Composition Methodology. July 2011. i. U.S. Environmental Protection Agency. Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air. Office of Air and Radiation: Natural Gas Star. Washington, DC. February 2004. j. U.S. Environmental Protection Agency. Pro Fact Sheet No. 301. Convert Pneumatics to Mechanical Controls. Office of Air and Radiation: Natural Gas Star. Washington, DC. September 2004. k. Canadian Environmental Technology Advancement Corporation (CETAC) - WEST. Fuel Gas Best Management Practices: Efficient Use of Fuel Gas in Pneumatic Instruments. Prepared for the Canadian Association of Petroleum Producers. May 2008 **6.2.2.2 Representative Pneumatic Controller Device Emissions**  For purposes of this guideline, continuous bleed pneumatic controllers are classified into two ty pes based on their emissions rates: (1) high bleed controllers and (2) low bleed controllers. A controller is considered to be high bleed when the continuous bleed emissions are in excess of 6 scfh, while low bleed devices bleed at a rate less than or equal to 6 scfh. 66

66 The classification of high bleed and low bleed devices originated from a report by Pacific Gas & Electric (PG&E) and the Gas Research Institute (GRI) in 1990 titled “Unaccounted for Gas Project Summary Volume.” This classification wa s adopted fo r 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***E.O. 12866 Review

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6 - 6 Pneumatic Controllers In support of the development of th e 2012 NSPS, and these guidelines, we consulted information in the appendices of the Natural Gas STAR L essons Learned document on pneumatic devices, subpart W of the GHGRP, the GHG Inventory , as well as pneumatic controller vendor information used during the development of the 2012 NSPS. 67 The data obtained from vendors included emission rates, costs, and any other pertinent information for each pneumatic controller model (or model family). All pneumatic controllers that a vendor offered were itemized and in quiries were made into the specifications of each device and whether it was applicable to ONG operations. High bleed and low bleed devices were differentiated using the 6 scfh threshold. Although, b y definition, a low bleed device can emit up to 6 scfh, through vendor rese arch, a ty

pical low bleed device available currently on the market emits lower than the maximum rate allocated for the device type. Specifically, low bleed devices on the market today have bleed rates from 0.2 scfh up to 5 scfh. Similarly , the available bleed rates for a high bleed device vary

significantl y from venting as low as 7 scfh to as high as 100 scfh. 68 , 69 While the vendor data provides useful information on specific makes and models, it did not yield sufficient information about the prevalence of each model type in the population of devices in the ONG source category , which is an important factor in develo ping a representative emission factor. Therefore, in support of these guidelines, we have determined that the best available emissions estimates for pneumatic controllers in the production segment are from the GHGRP. F or the natural gas processing segment we determined that the quantified representative methane emissions from a continuous bleed pneumatic controller in the natural gas processing segment based on natural gas emission rates presented in Volume 12 of the EPA/GRIreport used in the 2012 NSPS TSD is the best available emissions information 70

. The basic approach used for this anal ys is of emissions from pneumatic controllers was to first approximate the natural gas emissions from an average high bleed and low bleed pneumatic rates’ of 0.1 to 0.5 cubic feet per minute are considered to be ‘ high bleed’ types (PG&E 1990).” This range of bleed rates is equivalent to 6 to 30 cubic feet per hour. 67 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution

– Background Technical Support Document for Proposed Standards . July 2011. EPA Document Number EPA - 453/R- 11 - 002. 68 U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: Background Technical Support Document . Climate Change Division. Washington, DC. November 2010. 69 All rates are listed at an assumed supply gas pressure of 20 psig. 70 Ta ble 4 - 11, page 56. epa.gov/gasstar/tools/related.html***E.O. 12866 Review

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6 - 7 Pneumatic Controllers controller in the produc tion and processing segments and then estimate methane and VOC emissions using a representative gas composition. 71 A bleed rate of 1.39 scfh was used for a low bleed c ontroller, and a bleed rate of 37.3 scfh was used for a high bleed controller. The specif ic gas composition ratio used for the production and processing segments was 0.278 pounds VOC per pound methane. Table 6 - 2 summarizes the estimated bleed emissions for a representative pneumatic controller b y i ndustry segment (for production and processing segments) and device ty pe. **Table 6 -**  **2 . Average Emission Rates for**  **High bleed and**  **Low bleed Pneumatic Controllers in**  **the ONG**  **Source Category a**  **Industry Segment High bleed**  **(tpy) Low** **bleed (tpy)**  **Methane VOC**  **Methane VOC**  ONG Productionb 5.3 1.47 0.2 0.06 Natural Gas Processing d 1.00 0.28 1.0 0.28

a. The conversion factor used in this analysis is 1 Mcf of methane is equal to 0.0208 tons methane. b. Natural Gas Production methane emissions are derived from the Greenhouse Gas Reporting Program (subpart W). c. Oil production methane emissions are derived from the Greenhouse Gas Reporting Program (subpart W). It is assumed only continuous bleed devices are used in oil production. d. Natural gas processing segment methane emissions are derived from Volume 12 of the 1996 GRI report. Emissions from devices in the processing segment were determined based on data available for snap - acting and continuous ble ed devices. Further distinction between high and low bleed could not be determined based on available data. For the natural gas processing segment, it is assumed that existing natural gas plants have already replaced pneumatic controllers with other types of controls (i.e., an instrument air system) and any high bleed devices that remain are safety related. For the natural gas processing segment, this anal ysis assumes that existing natural gas plants have already replaced pneumatic controllers with other types of controls (i.e., an instrument air sy stem) and any high bleed devices that remain are safety relat ed. 

### 6.3 **Available Controls and Regulatory A**  **pproaches 6.3.1**  **Available VOC Emission Control Options** Although pneumatic controllers have relativel y small emissions individually, due to the large population of these devices the cumulative VOC emissions for the industry are significant. The following sections provide a summary of options for reducing VOC em issions from

71 Memorandum to Bruce Moore from Heather Brown. Composition of Natural Gas for Use in the Oil and Natural Gas Sector Rulemaking . EC/R, Incorporated. June 29, 2011.***E.O. 12866 Review

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6 - 8 Pneumatic Controllers pneumatic controllers including: replacing high bleed controllers with low bleed controllers or zero bleed controllers, driving controllers with instrument air rather than natural gas, using non gas - driven controllers, and enhanced maintenance. Although intermittent controllers do not continuously

bleed, this guideline assumes that these controllers are not alway s used in the same functional application as continuous bleed controllers and are, therefore, no t an appropriate VOC emissions control option for all continuous bleed controllers. For the purposes of this guideline both intermittent and no - bleed controllers meet the definition of a low bleed controller. Sections 6.3.1.1 and 6.3.1.2 discuss the contro l of VOC emissions by replacing a high bleed device with a low bleed device, and driving controllers with instrument air rather than natural gas, including the estimated costs of these options. Given applicability , efficiency and the expected costs, other options (i.e., mechanical controls and enhanced maintenance) are only briefl y discussed in sections 6.3.1.3 and 6.3.1.4. **6.3.1.1 Install a**  **Low bleed Device in Place of a**  **High bleed Device**  Description As discussed previousl y, low bleed controllers generall y provide the same operational function as a high bleed controller, but have lower continuous bleed emissions. Control Effectiveness We estimate on average that 1.85 tons of VOC will be reduced annuall y per device in the production segment from installing a low bleed device in place of a high bleed device. There are certain situations in which replacing and retrofitting are not feasible, such as instances where a minimal response time is needed, cases wh ere large valves require a high bleed rate to actuate, or a safety isolation valve is involved. Based on criteria provided b y the Natural Gas STAR Program, we assumed about 80 percent of high bleed devices can be replaced with low bleed devices throughout the production segment. For natural gas processing plants, we assume that instrument air sy stems are used to power pneumatic controllers and that any natural gas - driven pneumatic controllers in use are required for safety and functional reasons. Thus, there will be no emission reduction s in the natural gas processing segment. Applicability

of low bleed controllers may depend on the function carried out by the controller . Low bleed pneumatic controllers may not be applicable for replacement of high bleed devices because a process conditio n may require a fast or precise control response minimize***E.O. 12866 Review

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6 - 9 Pneumatic Controllers deviation from the desired set point. A slower acting low bleed controller could potentially result in damage to equipment and/or become a safety issue because it may not be able to respond as quickly as a high bleed controller. An example of this is a compressor where pneumatic controllers may

monitor the suction and discharge pressure and actuate a recycle when one or the other is out of the specified target range. Other scenarios for fast and prec ise control include transient (non - steady state) situations where a gas flow rate may fluctuate widely or unpredictabl y. This situation requires a responsive high bleed device to ensure that the gas flow can be controlled in all situations. Temperature and level controllers are typ ically present in control situations that are not prone to fluctuate as widely or where the fluctuation can be readil y and safel y accommodated by the equipment. Therefore, such processes can ty picall y accommodate control from a lo w bleed device, which is slower - acting and less precise. Cost Impacts Costs were based on vendor research as a result of updating and expanding upon the information given in the appendices of the Natural Gas STAR L essons Learned document on pneumatic controllers. 72 As Table 6 - 3 indicates, the average cost for a low bleed pneumatic controller is $2,698, while the average cost for a high bleed pneumatic controller is $2,471. 73 In order to analyz e cost impacts, the average cost to install a new low bleed pneumatic controller was annualized for a 15 year period using a 7 percent interest rate. This equates to annualized cost s of around $271 per low bleed device for the production segment.

72 U.S. Environmental Protection Agency. Lessons Learned f rom Natural Gas STAR Partners . Convert Gas Pneumatic Controls to Instrument Air . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. February 2004 73 Costs are estimated in 2012 U.S. Dollars.***E.O. 12866 Review

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6 - 10 Pneumatic Controllers

**Table 6 -**  **3 . Cost Projections for Represe**  **ntative Pneumatic Controllers a** 

**Device Minimum** 

**Cost ($2012)**  **Maximum**

**Cost ($2012)**  **Average Cost**

**($2012)** High bleed Controller $387 $7,398 $2,471 Low bleed Controller $554 $9,356 $2,698 a. Cost data from the 201l NSPS TSD was converted to 2012 dollars (from 2008 dollars) using the Federal Reserve Economic Data GDP Price Deflater. During the development of the 2012 NSPS, major pneumatic controller vendors were surveyed for costs, emission rates, and any other pertinent information. Monetary savings associated with retaining natural gas that would have been emitted was estimated based on a natural gas value of $4.00 per Mcf. 74 The use of a low bleed pneumatic controller is estimated to reduce m ethane emissions by 5.1 tpy (245 Mcf/y

r) (using the conversion factor of 0.0208 tons methane per 1 Mcf) over the use of a high bleed pneumatic controller. Assuming natural gas in the production segment is 82.8 percent methane b y volume, this equals 296 Mcf natural gas recovered per ye ar. Therefore, the value of recovered natural gas from one pneumatic controller in the production segment is approximately $1,184. Table 6 - 4 presents the estimated cost of control per ton of VOC reduced for replacing a high ble ed pneumatic controller with a new low bleed pneumatic controller in the production segment of the ONG source category . **Table 6 -**  **4 . VOC Cost of Control for**  **Replacing an Existing High Bleed Pneumatic**

**Controller With a New Low B**  **leed Pneumatic Controller**  **Segment Average**  **Capital Cost**  **s per**  **Unit ($2012)**  **a,c Total Annual** 

**Cost s**  **per Unit ($2012/yr)**  **b,c VOC Cost of** 

**Control ($2012/ton)**  **c Without**  **Savings With** 

**Savings Without** 

**Savings With** 

**Savings** ONG Production $2,698 $296 ($886 ) $210 ($627 ) a. Average capital cost s of a low bleed d evice as summarized in Table 6 - 3 . b. Annualized cost s assume a 7 percent interest rate over a 15 year equipment lifetime. c. Cost data from the 2012 NSPS was converted to 2012 dollars using the Federal Reserve Economic Data GDP Price Deflater (5.69 percent).

74 U.S. Energy Information Administration. Annu al U.S. Natural Gas Wellhead Price. Energy Information Administration. Natural Gas Navigator . Retrieved online on 12 Dec 2010 at http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm***E.O. 12866 Review

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6 - 11 Pneumatic Controllers **6.3.1.2 Instrument Air Systems**  Description The major components of an instrument air conversion project include the compressor, power source, deh ydrator, and volume tank. The following is a description of each component as described in the Natural Gas STAR document, Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air: 75 1) Compressors used for instrument air delivery are available in various types and sizes, from centrifugal (rotary

screw) compressors to reciprocating piston (positive displacement) types. The size of the compressor depends on the size of the facility, the number of control devices operated b y the s ys tem, and the ty pical bleed rates of these devices. The compressor is usually driven b y an electric motor that turns on and off, depending on the pressure in the volume tank. For reliability , a full spare compressor is normally installed. A minimum amount of electrical service is required to power the compressors. 2) A critical component of the instrument air control sy stem is the power source required to operate the compressor. Since high - pressure natural gas is abundant and readily available, natural g as pneumatic systems can run uninterrupted on a 24 - hour, 7 - day per week schedule. The reliability

of an instrument air s ys tem, however, depends on the reliability of the compressor and electric power suppl y. Most large natural gas plants have either an exi sting electric power supply or have their own power generation s ys tem. For smaller facilities and in remote locations, however, a reliable source of electric power can be difficult to assure. In some instances, solar- powered battery- operated air compressor s can be cost effective for remote locations, which reduce both VOC emissions and energy consumption. Small natural gas - driven fuel cells are also being developed. 3) Deh ydrators, or air dryers, are also an integral part of the instrument air compressor sy ste m. Water vapor present in atmospheric air condenses when the air is pressurized and cooled, and can cause a number of problems to these sy stems, including corrosion of the instrument parts and blockage of instrument air piping and controller orifices.

75 U.S. Env ironmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Convert Gas Pneumatic Controls to Instrument Air . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. 2006.***E.O. 12866 Review

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6 - 12 Pneumatic Controllers 4) The volume tank holds enough air to allow the pneumatic control s ys tem to have an uninterrupted supply

of high pressure air without having to run the air compressor continuously . The volume tank allows a large withdrawal of compressed air for a short time, su ch as for a motor starter, pneumatic pump, or pneumatic tools without affecting the process control functions. Compressed air may

be substituted for natural gas in pneumatic sy stems without altering any of the parts of the pneumatic controller. The use of instrument air eliminates natural gas emissions from natural gas - driven pneumatic controllers. All other parts of a natural gas pneumatic sy stem will operate the same way with instrument air as they do with natural gas. The conversion of natural gas pneumatic controllers to instrument air sy stems is applicable to all natural gas facilities with electrical service available. Figure 6 - 1 illustrates a diagram of a natural gas pneumatic control s ystem. 76 Figure 6 - 2 illustrates a diagram of a compressed instrument air control sy stem. Control Effectiveness The use of instrument air eliminates natural gas emissions from the pneumatic controllers; however, the sy stem is only applicable in locations with access to a sufficient and consistent supply

of electrical powe r. Instrument air sy stems are also usually installed at facilities where there is access to high Btu gas, a high concentration of pneumatic control valves and the presence of an operator that can ensure the s ys tem is properl y functioning. 77

76 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Convert Gas Pneumatic Controls to Instrument Air . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. 2006. 77 Ibid.***E.O. 12866 Review

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

**Figure 6 -**  **2 . Compressed Instrument Air Control System** ***E.O. 12866 Review

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6 - 14 Pneumatic Controllers Cost Impacts Instrument air conversion requires additional equipment to properl y compress and control the pressurized air. The size of the compressor will depend on the number of control loops present at a location. A control loop consists of one pneumatic controller a nd one control valve. The volume of compressed air suppl y for the pneumatic system is equivalent to the volume of gas used to run the existing instrumentation, adjusted for air losses during the drying process. The current volume of gas usage can be determ ined by direct metering if a meter is installed. Otherwise, an alternative rule of thumb for sizing instrument air sy stems is one cubic foot per minute (cfm) of instrument air for each control loop. As the sy stem is powered by electric compressors, the s ys tem requires a constant source of electrical power and a back- up s ys tem to operate the controllers in the event of interruption of the electrical suppl y. Table 6 - 5 outlines three different sized instrument air sy stems including the compressor power require ments, the flow rate provided from the compressor, and the associated number of control loops. **Table 6 -**  **5 . Compressor Power Requirements for Representative Instrument Air Systems**  **a**

**Compressor Power Requirements b**  **Flow Rate (cfm)**  **Control Loops**

**( Loops/Compressor)**  **Size of Unit Hp**  **kW** Small 10 13.3 30 15 Medium 30 40 125 63 Large 75 100 350 175 a. Based on rules of thumb stated in the Natural Gas STAR document, Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air. Natural Gas STAR Program. Washington, DC. 2006. b. Power is based on the operation of two compressors operating in parallel (each assumed to be operating at full capacity 50 percent of the year). The primary

costs associated with conversion to instrument air sy stems are the initial capital expenditures for installing compressors and the related equipment and operating costs for electrical energy

to power the compressor motor. This equipment includes a compressor, a power source, a deh ydrator , gas supply piping, control instruments, valve actuators and a storage vessel. The total cost, including installation and labor, of three representative sizes of compressors were evaluated based on assumptions found in the Natural Gas STAR document, “Lessons Learned: Co nvert Gas Pneumatic Controls to Instrument Air” and summarized in Table 6 - 6. 78

78 Ibid.***E.O. 12866 Review

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6 - 15 Pneumatic Controllers For new natural gas processing plants, the cost - effectiveness of the three representative instrument air sy stem sizes was evaluated in the 2015 NSPS TSD based on the emissions mi tigated from the number of control loops the s ystem can provide and not on a per device basis. This approach was chosen because we assume new processing plants will need to provide instrumentation of multiple control loops and size the instrument air sy ste m accordingl y. Table 6 - 7 summarizes the natural gas processing segment cost of control per ton of VOC reduced for three sizes of representative instrument air s ys tems. For existing natural gas processing plants, we assume that they have already upgraded to instrument air unless the function has a specific need for a high bleed pneumatic controller, which would most likely

be safety related. The cost of converting the pneumatic controllers to instrument air includes the capital cost s of $2, 000 for the ductwork and annual cost s of $285 (assuming a 10 year equipment life at 7% interest). The VOC cost of control for converting pneumatic controllers to instrument air for processing plants that already have instrument air ranges from $6 to $68 pe r ton of VOC removed, depending on the size of the instrument air sy stem. For natural gas processing , the cost of control of the three representative instrument air sy stems was evaluated based on the emissions mitigated from the number of control loops th e sy stem can provide and not on a per controller basis. This approach was chosen because we assume new processing plants will need to provide instrumentation for multiple control loops and size the instrument air sy stem accordingl y. We also assume that exi sting processing plants have already upgraded to instrument air unless the function has a specific need for a high bleed pneumatic controller, which would most likely be safety related. Table 6 - 7 summarizes the natural gas processing segment cost of contro l per ton of VOC reduced for three sizes of representative instrument air sy stems. **6.3.1.3 Electrically**  **Powered Systems in Place of Bleed Devices** Description Mechanical controls have been widely used in the ONG source category . They operate using a combination of levers, hand wheels, springs and flow channels with the most common mechanical control device being a liquid - level float to the drain valve position with mechanical***E.O. 12866 Review

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6 - 16 Pneumatic Controllers linkages. 79 Another device that is inc reasing in use is electrically powered controls. Sm all electrical motors (including solar powered) have been used to operate valves and have no VOC emissions. Solar powered control sy stems are driven by solar power cells that actuate mechanical devices usi ng electric power. As such, solar cells require some type of back - up power or storage to ensure reliability. Control Effectiveness 80 Application of mechanical controls is limited because the control must be located in close proximity to the process measure ment. Mechanical sy stems may have difficulty

handling larger flow fluctuations. Electrically powered valves are only

reliable with a constant supply of electricity. These controllers can achieve a 100 percent reduction in VOC emissions where applicable. Co st Impacts Depending on suppl y of power, mechanical and solar power s ys tem costs can range from below $1,000 to $10,000 for an entire s ys tem. 81

79 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STA R Partners . Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas ST AR Program. Washington, DC. October 2006. 80 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Convert Gas Pneumatic Controls to Instrument Air . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. October 2006. 81 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Options for R educing Methane Emissions from Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas ST AR Program. Washington, DC. October 2006.***E.O. 12866 Review

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6 - 17 Pneumatic Controllers

**Table 6 -**  **6 .**  **Estimated Capital and Annual Costs of Representative Instrument Air Systems ($2012) Instrument**  **Air System Size**  **Compressor Tank**  **Air Dryer Total**  **Capital Cost**  **s a**  **Annualized**

**Capital Cost**  **s b**  **Labor Cost Total Annual**  **Costs c**  **Annualized Cos s**  **t**

**of Instrument Air**  **System** Small $3,987 $797 $2,391 $17,938 $2,553 $1,410 $9,168 $11,721 Medium $19,928 $2,391 $7,173 $77,716 $11,065 $4,580 $27,911 $38,976 Large $35,071 $4,783 $15,941 $143,476 $20,428 $6,340 $64,669 $85,097 a. Total Capital Cost includes the cost for two compressors, two tanks, an air dryer and installation. Installation costs are as sumed to be equal to 1.5 times the cost of capital. Equip ment costs were derived from the 2012 NSPS TSD. b. These costs have been converted to 2012 dollars using the Federal Reserve Economic Data GDP Price Deflater (Change in GDP: Im plicit Price Deflator from 2008 to 2012 (5.69 percent). 82 c. The annualized cost s were estimated using a 7 percent interest rate an d 10 year equipment life. Annual c osts include the cost of electrical power as listed in Table 6 - 8 and labor. **Table 6 -**  **7 . Cost of Control of Representative Instrument Air Systems in the Natural Gas Processing Segment ($2012)**  **System Size Number of** 

**Control Loops**  **VOC Annual**

**Emission Reduction**  **(tpy) a**  **Value of**

**Product Recovered**  **($2012/year) b**  **Annualized Cost s**  **of System**  **VOC Cost of Control ($2012/ton)**  **Without Savings**  **With**

**Savings Without** 

**Savings With** 

**Savings** Small 15 4.18 $3,682 $11,721 $8,039 $2,807 $1,926 Medium 63 17.5 $15,465 $38,976 $23,511 $2,223 $1,341 Large 175 48.7 $42,957 $85,097 $42,140 $1,747 $866 a. Based on the emissions mitigated from the entire system, which includes multiple control loops. b. Value of recovered product assume s natural gas processing is 82.9 percent methane by volume. A natural gas price of $4 per Mcf was assumed. 82 U.S. Bureau of Economic Analysis. Gross Domestic Product: Implicit Price Deflator (GDPDEF] , retrieved from FRED, Federal Reserve Bank of St. Louis. https://research.stlouisfed.org/fred2/series/GDPDEF/ March, 26, 2015.***E.O. 12866 Review

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6 - 18 Pneumatic Controllers **6.3.1.4 Enhanced Maintenance of Natural Gas**  **- Driven Pneumatic Controllers**  Manufacturers of pneumatic controllers indicate that emissions in the field can be higher than the reported gas consumption due to operating conditions, age, and wear of the device. 83 Examples of circumstances or factors that can contribute to this increase include: 84 , 85 1) Nozzle corrosi on resulting in more flow through a larger opening; 2) Broken or worn diaphragms, springs (e.g., spring broken that holds the supply pilot - plug on its seat), bellows, fittings (e.g., leaking tubing/tubing - fittings ) and nozzles; 3) Corrosives in the gas leading t o erosion and corrosion of control loop internals; 4) Improper installation; 5) Lack of maintenance (maintenance includes replacement of the filter used to remove debris from the suppl y gas and replacement of O - rings and/or seals); 6) Lack of calibration of the controller or adjustment of the distance between the flapper and nozzle; 7) Foreign material lodged in the pilot seat; 8) Debris/deposits on vent pilot plug. Material on the vent pilot can allow the controller to exhaust gas during the activation cycle; 9) Debris/deposits on the supply pilot plug. Material on the supply pilot can cause the introductio n of gas while the vent is open; or 10) Wear in the seal seat. The EPA prepared a white paper titled “Oil and Natural Gas Sector Pneumatic Devices” in 2014, requesting specific comment on available emissions data for pneumatic devices. One of the comments received regarding data presented in “Measurements of Methane Emissions at Natural Gas Production Sites in the United States” 86 was that the data set reported was do minated by

extreme values. The commenter noted that the highest emitting controllers are simply controllers emitting at a large rate, regardless of their service or design type. These

83 Ibid. 84 Ibid. 85 American Petroleum Institute (API). Pneum atic Controllers . Webinar Prepared and Presented to the U.S. Environmental Protection Agency. March 25, 2014. 86 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Pneumatic Devices . Report for Oil and Natural Gas Sector Compressors Review Pan el Office of Air Quality Planning and Standards (OAQPS). April 2014. Available at http://www.epa.gov/airquality/oilandgas/2014papers/***E.O. 12866 Review

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6 - 19 Pneumatic Controllers controllers can have high emissions because of factors, other than design, related to maintenance, malfunction, or defect. 87 Maintenance of pneumatics can correct many of these problems and can be an effective method for reducing emissions. Cleaning and tuning, in addition to repairing leaking gaskets, tubing fittings, and seals, can save 5 to 10 scfh per device. Eliminating unnecessary valve positioners can save up to 18 scfh per device. 88 **6.3.2 Existing Federal, State and Local Regulations**  **6.3.2.1 Federal Regulations that Specifically Require Control of VOC** 

**Emissions** Under the 2012 NSPS, new or modified continuous bleed natural gas - driven pneumatic controllers at natural gas processing plants are subject to a VOC emission limit of zero (equivalent to non - natural gas - driven pneumatic controllers). Continuous bleed natural gas driven pneumatic controllers in the production segment must have a bleed rate of 6 scfh or less. **6.3.2.2 State and Local Regulations**  **that Specifically Require Control of VOC**

**Emissions** States may

have permitting restrictions on VOC emissions that apply to an emissions source as a result of an operating, NSR NA, or PSD permit (e.g., on a case - by- case basis) requirements based on air quality maintenance or improvement goals of an area. Permits specify what construction is allowed, what emission limit s must be met, and often how the source must be operated. To assure that sources follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements For pneumatic controllers, Colorado and Wyoming have existing control requirements similar to those required under the 2012 NSPS. Other states have permitting and registration rules for controlling fugitive VOC emissions (which would include non - bleed emissions from pneumatic controllers).

87 Allen, David. Comments Provided to the EPA on Oil and Natural Gas Sector Pneumatic Devices -Peer Review Document . University of Texas at Austin. June 2014. 88 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. October 2006.***E.O. 12866 Review

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6 - 20 Pneumatic Controllers Colorado requires that no - or low bleed pneumatic controllers with a bleed rate of 6 scfh or less be installed for all new and existing applications (unless approved for use due to safety and/or process purposes) statewide (Regulation 7, XVIII.C.2). Where technically and economicall y f

easible, Colorado requires no - bleed pneumatic controllers at facilities that are connected to the electric grid and using electricity to power equipment. Wyoming requires the installation of low - or no - bleed pneumatic controllers with a bleed rate of 6 scf

h or less at all new facilities. Upon modification of facilities, new pneumatic controllers must be low - or no - bleed and existing controllers must be replaced with no - or low bleed controllers (at well site facilities only and not at natural gas processing plants). Although some local rule requirements do not specificall y require the control of VOC emissions from pneumatic controllers, local permit requirements ( such as those required by the Bay Area Air Quality Management District) may require that a permi t to operate applicant provide the number of high bleed and low bleed pneumatic devices in a permit application. Under some situations where facilities use high bleed devices, the permitting authority might require an owner or operator to provide device - sp ecific bleed rates and supporting documentation for each high bleed device. In cases where high bleed devices must be used, the permitting authority may require that the facility conduct fugitive monitoring and/or implement control requirements under condi tions of their permit to operate 89

. 

### 6.4 **Recommended RACT Level of Control** Sections 6.4.1 and 6.4.2 present the recommended RACT level of control/impacts for continuous bleed natural gas - driven pneumatic controllers located at natural gas processing plants and continuous bleed natural gas - driven pneumatic controllers located from the wellhead to the natural gas processing plant or point of custody trans fer to an oil pipeline . **6.4.1 Continuous Bleed Natural Gas -**  **Driven Pneumatic Controllers Located at a**  **Natural Gas Processing Plant** Based on our evaluation of available data obtained in the development of the 2012 NSPS, peer review comments received on the “Oil and Natural Gas Sector Pneumatic Devices” white paper, and existing regulations that control VOC emissions from pneumatic controllers, we

89 Cheng, Jimmy. Permit Handbook. Chapter 3.5 Natural Gas Facilities and Crude Oil Facilities. Bay Area Air Quality Management District. September 16, 2013.***E.O. 12866 Review

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6 - 21 Pneumatic Controllers recommend that VOC emissions from an individual continuous bleed pneumatic controller located at a natural gas processing plant be controlled by RACT. As noted in section 6.3.2, both Colorado and Wyoming require either low - or no - bleed controllers (where a high bleed controller is defined as emitting at least 6 scfh); and the 2012 NSPS requires that new and modified individual continuous bleed pneumatic controllers at natural gas processing plants have a natural gas bleed rate of zero scfh (unless there are functional needs, including but not limited to response time, safety and positive actuation, requiring a bleed rate greater than zero scfh) . For existing individual continuous bleed pneumatic controllers at natural gas processing plants, our RACT recommendation is that controllers have a natural gas bleed rate of zero scfh (unless there are functional needs, including but not limited to response time, safety and positive actuation, requiring a bleed rate greater than zero scfh) . Our rationale for selecting a natural bleed rate of zero scfh (with functional and safety exceptions) for our recommended RACT is based on the ability of most large natural gas processing plants to install and utilize an instrument air sy stem . Additionally , most large plants have either an existing electric power supply or have their own power generation s ys tem with an abundance of high - pressure natural gas available to run the required compressor and it is assumed that most plants may already have an instrument air sy stem on - site. As discus sed in section 6.3.1.2 of this c hapter, b y using an instrument air system, compressed air may

be substituted for natural gas in pneumatic sy stems without altering any of the parts of the pneumatic controller . Therefore, the use of instrument air eliminates natural gas and VOC emissions from pneumatic controllers and supports a natural gas bleed rate of zero scfh. In order to meet an emission limit of zero scfh, natural gas processing plants would likely need to use an instrument air sy stem. The use of instrument air eliminates natural gas and VOC emissions from natural gas - driven pneumatic controllers. We believe that most natural gas processing plants already meet the recommended RACT level of control by driv ing controllers with instrument air or other non - gas - driven controls unless there is a specific need for a high bleed pneumatic controller. Nonetheless, for those natural gas processing plants that do not have an installed instrument air sy stem , the cost of control of installing three representative instrument air sy stems was evaluated under the 2012 NSPS based on the emissions mitigated from the number of control loops the sy stem can provid e (see section 6.3.1.2 of this c hapter). Based on this analy sis, the cost of this option was considered to be reasonable for natural gas processing***E.O. 12866 Review

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6 - 22 Pneumatic Controllers plants (see Table 6 - 7 of section 6.3.1.2 of this c hapter). The cost of control per ton of VOC reduced was estimated at $1,747 - $2,807 without savings and $866 - $1,926 with savings. For determining potential cost impacts, a major assumption made was that processing plants are constructed at a location with sufficient electrical service to power the instrument air compression sy stem. In summary , we recommend the following RAC T for each continuous bleed natural gas driven pneumatic controller located at a natural ga s processing plant : RACT for Each Continuous Bleed Natural Gas - Driven Pneumatic Controller Located at a Natural Gas Processing Plant : 90 Each continuous bleed natural gas driven pneumatic controller located at a natural gas processing plant must have a natural gas bleed rate of zero scfh (unless there are functional needs, including but not limited to response time, safety and positive actuation, requiring a bleed rate greater than zero scfh). **6.4.2 Continuous Bleed Natural Gas -**  **Driven Pneumatic Controllers Located from**  **the Wellhead to the Natural Gas Processing Plant or Point of Custody Transfer to an Oil Pipeline**  Based on our evaluation of available data obtained in the development of the 2012 NSPS, peer review comments received on the “Oil and Natural Gas Sector Pneumatic Devices” white paper, and existing regulations that control VOC emissions from pneumatic cont rollers, we recommend that VOC emissions from continuous bleed natural gas - driven pneumatic controllers located from the wellhead to the natural gas processing plant or point of custody transfer to an oil pipeline be controlled b y RACT. As indicated in se ction 6.2.2 of this c hapter, emissions from pneumatic controllers are highl y variable, and a low bleed controller can emit up to 6 scfh, which is higher than the expected emissions from the ty pical low bleed device currentl y available. B oth Colorado and Wyoming conditionall y require either low - or no - bleed controllers (where a high bleed controller is defined as emitting greater than 6 scfh); and the 2012 NSPS requires that new and modified individual continuous bleed pneumatic controllers have a bleed rate of 6 scfh or less (unless there are functional needs, including but not limited to response time, safety and positive actuation,

90 In the NSPS, we excluded from the NSPS affected facility status non - natural gas - driven pneumatic controllers located at natural gas processing plants. Natural gas - driven controllers exempt fr om the zero VOC emission standard under the functional needs exclusion would still be affected facilities and would have certain tagging, recordkeeping and reporting requirements.***E.O. 12866 Review

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6 - 23 Pneumatic Controllers requiring a bleed rate greater than 6 scfh) . For purposes of this guideline, and consistent with the definition of high bleed controller used for the 2012 NSPS and both the Wyoming and Colorado state regulations , a high bleed pneumatic device is defined as emitting greater than 6 scfh to the atmosphere. Although both Wyoming and Colorado specifically require low bleed or no - blee d pneumatic controllers in place of high bleed controllers (where technicall y and economically feasible), we are recommending a RACT emission limit of 6 scfh (unless there are functional needs, including but not limited to response time, safety and positiv e actuation, requiring a bleed rate greater than 6 scfh) apply to each continuous bleed pneumatic controller. This approach allows flexibility

in how a source chooses to limit VOC emissions from an applicable individual pneumatic controller and acknowledge s that there may be circumstances where it is not practical to meet a 6 scfh limit. B y requiring a limit be met, facilities have the option of controlling emissions by

one or more options pres ented in section 6.3.1 of this c hapter (e.g., replacing a high b leed device with a low bleed device and implement enhanced monitoring to mitigate increased VOC emissions from poor maintenance/poor operation) depending on site - specific circumstances. We are including this flexibility in our recommended RACT to address the varied control options and applicability issues (e.g., instrument air sy stems require access to electrical power or a back - up pneumatic controller and access to electric power or back up pneumatic controllers may

not be available in remote locations) pres ented in section 6.3.1 of this c hapter. Although facilities would have flexibility in how they

meet the recommended RACT level of control, b y establishing an emission limit equal to the maximum emissions allowed for a low bleed device (6 scfh) for continuous bleed natural gas - driven pneumatic controllers located from the wellhead to the natural gas processing plant or point of custody transfer to an oil pipeline , it is assumed that most facilities would likely replace high bleed controllers with low bleed controllers (it is assumed about 80 percent of high bleed devices can be replaced with low bleed devices). 91 For the production segment, it is estimated, on average, that 1.85 tons of VOC will be reduced annuall y per device in th e production segment from installing a low bleed device in place of a high bleed device.

91 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. October 2006.***E.O. 12866 Review

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6 - 24 Pneumatic Controllers As presented in section 6.3.1.1 o f this c hapter, the cost of replacing a high bleed device with a new low bleed device is on the order of $2,698 per device, and the co st of control in the productio n segment is estimated to be $210 per ton of VOC emissions without savings. Considering the cost savings of gas recovered from installing a low bleed device in place of a high bleed device, it is estimated that there would be an overall net savings. In summary , we recommend the following RACT for each single continuous bleed natural gas - driven pneumatic co ntroller located from th e wellhead to the natural gas processing plant or point of custody

transfer to an oil p ipeline: RAC T for Each Single Continuous Bleed Natural Gas - Driven Pneumatic Controller Located from the Wellhead to the Natural Gas Processing Plant or Point of Custody Transfer to an Oil Pipeline : Each pneumatic controller, which is a single continuous bleed natural gas - driven pneumatic controller 92 must have a natural gas bleed rate less than or equal to 6 scfh (unless there are functional needs, including but not limited to response time, safety and positive actuation, requiring a bleed rate greater than 6 scfh). 

### 6.5 **Factors to Consider in Developing Pneumatic Controller**  **Compliance Procedures 6.5.1**  **ONG Production (Individual**  **Continuous Bleed Pneumatic Controller with a Natural Gas Bleed Rate Greater than 6 scf Located from the Wellhead to**  **the Natural Gas Processin g Plant**  **or Point of Custody Transfer to an Oil Pipeline**  **)** To ensure that each continuous bleed natural gas - driven pneumatic controller located from the wellhead to the natural gas processing plant or point of custody transfer to an oil pipeline are operated with a natural gas bleed rate less than or equal to 6 scfh (the recommended RACT level of control), we recommend that you specify operating, recordkeeping and reporting requirements to document compliance. We also recommend that you require t hat each pneumatic controller be tagged with the month and year of installation and identification information that allows traceability

to manufacturer’s documentation.

92 In the NSPS, we excluded from NSPS affected facility status continuous bleed natural gas - driven pneumatic controllers with a bleed rate not greater than 6 scfh (low bleed controllers) located in the production segment. Continuous bleed natural gas - driven controllers exempt from the 6 scfh bleed rate emission standard under the functional needs exclusion would still be affected facilities and would have certain tagging, recordkeeping and reporting requirements.***E.O. 12866 Review

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6 - 25 Pneumatic Controllers We suggest that regulatory agencies require owners and operators of continuous bleed natural gas - driven pneumatic controllers maintain records that (1) document the location and manufacturer’s specifications of each pneumatic controller; (2) if applicable, provides a demonstration as to why

the use of a pneumatic controller with a natural ga s bleed rate greater than 6 scfh is required (the recommended RACT level of control); and (3) document deviations in cases where a pneumatic controller was not operated in compliance with RACT. We also recommend that regulatory agencies require owners an d operators to submit annual reports that includes (1) if applicable, documentation that the use of a pneumatic controller with a natural gas bleed rate greater than 6 standard cubic feet per hour is required and the reasons wh y; and (2) the records of dev iations that occurred during the reporting period. The Appendix to this document presents example model rule language that incorporates compliance elements recommended in this section that states may choose to use in whole or in part when implementing RACT . **6.5.2 Natural Gas Processing Segment (Individual Continuous Bleed Natural**  **Gas -**  **Driven Pneumatic Controller Located at a Natural Gas Processing**  **Plant)** To ensure each continuous bleed natural gas - driven pneumatic controller at natural gas processing plants is operated with a natural gas bleed rate of zero (the recommended RACT level of control), we suggest that regulatory agencies specify

operating, recordkeeping and reporting requirements to document compliance. We also suggest that regulatory agencies requ ire that each pneumatic controller be tagged with the month and year of installation and identification information that allows traceability to manufacturer’s documentation. We recommend that regulatory agencies require owners and operators of pneumatic co ntrollers maintain records that (1) document the location and manufacturer’s specifications of each pneumatic controller; (2) document that the natural gas bleed rate is zero; and (3) document deviations in cases where a pneumatic controller was not operat ed in compliance with RACT. We also recommend that regulatory agencies require owners and operators to submit annual reports that include the records of deviations that occurred during the reporting period. The Appendix to this document presents example model rule language that incorporates compliance elements recommended in this section that States may choose to use in whole or in part when implementing RACT.***E.O. 12866 Review

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7 - 1 Pneumatic Pumps 

### 7.0 **PNEUM AT**  **IC PUMPS** The ONG production industry u ses a variety

of pneumatic gas - driven pumps where there is no reliable electrical power to "control processing problems and protect equipment.” 93 Pneumatic pumps are “small positive displacement, reciprocating units used throughout the ONG production source category to inject precise amounts o f chemicals into process streams or for freeze protection glycol circulation.” 94 Most chemical injection pumps fall into two main ty pes: (1) diaphragm pumps, generall y used for heat tracing or (2) plunger/piston, generall y used for chemical and methanol inj ection. Pneumatic pumps driven by natural gas emit natural gas, which contains VOC. Other typ es of pneumatic pumps may be driven by

gases other than natural gas and, therefore, do not emit VOC. The focus of this guideline is natural gas - driven pneumatic pumps. This chapter provides a description of pneumatic pumps that are used in the ONG source category , including their function and associated emissions. This chapter also provides control techniques used to reduce VOC emissions from pneumatic pumps, along with costs and emission reductions. Finall y, this chapter provides a discussion of our recommended RACT and the associated VOC emission reductions and cost impacts for pneumatic pumps. 

### 7.1 **Ap plicability**  For the purposes of this guideline, a pneumatic pump is a positive displacement reciprocating unit used for injecting precise amounts of chemicals into a process stream or for gl ycol circulation. The pneumatic pump may use natural gas or another gas to drive the pump. The emissions and emissions control disc ussed herein would appl y to natural gas - driven chemical/methanol and diaphragm pump located at natural gas processing plants, and natural gas - driven chemical/methanol and diaphragm pumps located from the wellhead to the point of custody transfer to the natural gas transmission and storage segment .

93 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 13: Chemical Injection Pumps . Prepared for the Gas Research Institute and Environmental Protection Agency. EPA - 600/R - 96 - 080b. June 1996. 94 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Options for Reducing Met hane Emissions from Pneumatic Devices in the Natural Gas Industry . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. October 2006.***E.O. 12866 Review

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7 - 2 Pneumatic Pumps 

### 7.2 **Process Description and Emission Sources 7.2.1**  **Process Description** As noted above, pneumatic pumps are “positive displacement, reciprocating units used for injecting precise amounts of chemicals into a process stream or for gl ycol circulation.” 95 Pneumatic pumps often make use of gas pressure where electricity is not readily

available. 96 In the production segment, the supply gas is mostly

produced natural gas, whereas in the processing segment, the suppl y gas may be compressed air. For natural gas - driven pneumatic pumps, characteristics that affect VOC emissions include the frequency of operation, the size of the unit, the supply

gas pressure, and the inlet natural gas composition. 97 Pneumatic pumps are generall y used for one of three purposes: gl yc ol circulation in dehydrators, hot oil circulation for heat tracing/freeze protection, or chemical injection. Glycol dehydrator pumps may

recover energy

from the high - pressure rich gl ycol/gas mixture leaving the absorber and use that energy to pump the low - pressure lean gl ycol back into the absorber. 98 Diaphragm pumps are commonly used to circulate hot gl ycol or other heat - transfer fluids in tubing covered with insulation to prevent freezing in pipelines, vessels , and tank s. Chemical injection pumps, i.e., piston/plunger pumps or small diaphragm pumps, inject small amounts of chemicals such as methanol to prevent hydrate formation or corrosion inhibitors into process streams to regulate operations of a plant and protect the equipment. Pneumatic pumps have two major components, a driver side and a motive side, which operate in the same manner but with different reciprocating mechanisms. Pressurized gas provides energy

to the driver side of the pump, which operates a piston o r flexible diaphragm to draw fluid into the pump. The motive side of the pump delivers the energy to the fluid being moved in order to discharge the fluid from the pump. The natural gas leaving the exhaust port of

95 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. October 2006. 96 Ibid. 97 Ibid. 98 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Pneumatic Devices . Report for Oil and Natural Gas Sector Pneumatic Devices Review Panel. Office of Air Quality Planning and Standards (OAQPS). April 2014. Available at http://www.epa.gov/airquality/oilandgas/2014papers/***E.O. 12866 Review

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7 - 3 Pneumatic Pumps the pump is either directly discharged int o the atmosphere or is recovered and used as a fuel gas or stripping gas. 99 Chemical injection pumps are positive displacement, reciprocating units designed to inject precise amounts of chemical into a process stream. Positive displacement pumps work by al lowing a fluid to flow into an enclosed cavity from a low - pressure source, trapping the fluid, and then forcing it out into a high - pressure receiver by decreasing the volume of the cavity. A complete reciprocating stroke includes two movements, referred to as an upward motion or suction stroke, and a downward motion or power stroke. During the suction stroke, the chemical is lifted through the suction check valve into the fluid cylinder. The suction check valve is forced open by the suction lift produced by the plunger and the head of the liquid being pumped. Simultaneously, the discharge check valve remains closed, thus allowing the chemical to remain in the fluid chamber. During the power stroke, the plunger assembl y is forced downwards, immediately

shutti ng off the suction check valve. Simultaneously, the chemical is displaced, forcing open the discharge check valve and allowing the fluid to be discharged. 100 Ty pical chemicals injected in an oil or natural gas field are biocides, demulsifiers, clarifiers, co rrosion inhibitors, scale inhibitors, hydrate inhibitors, paraffin dewaxers, surfactants, oxygen scavengers, and H 2 S scavengers. These chemicals are normall y injected at the wellhead and into gathering lines or at production separation facilities. Since th e injection rates are ty picall y small, the pumps are also small. They are often attached to barrels containing the chemical being injected. 101 Diaphragm pumps are positive displacement pumps, meaning they use contracting and expanding cavities to move fluid s. Diaphragm pumps work by flexing the diaphragm out of the displacement chamber. When the diaphragm moves out, the volume of the pump chamber increases and causes the pressure within the chamber to decrease and draw in fluid. The inward stroke has the opp osite effect, decreasing the volume and increasing the pressure of the chamber to move out fluid. 102

99 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. October 2006. 100 Ibid. 101 Ibid. 102 GlobalSpec. Diaphragm Pumps Information . Available online - http://www.globalspec .com /learnmore/flow

_transfer_control/pumps/diaphragm_pumps .***E.O. 12866 Review

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7 - 4 Pneumatic Pumps Not all pneumatic pumps are natural gas - driven. At sites without electrical service sufficient or reliable enough to power an instrument air compressor control sy stem, mechanical or electrically

powered pneumatic pumps may be used. Where reliable electrical service is available, sources of power other than pressurized natural gas, such as compressed instrument air may be used. Because these devices are not natural gas - driven, they do not directly

release natural gas or VOC emissions. Instrument air s ys tems are feasible onl y at ONG locations where the devices can be driven by compressed instrument air sy stems and have electrical service sufficient and reliable enough to power a compressor. This anal ys is assumed that natural gas processing plants are likely to have electrical service sufficient to power an instrument air sy stem, and that most existing gas processing plants use instrument air instead of natural gas driven pumps 103 The application of electrical controls is discussed further in section 7.3 of this c hapter. **7.2.2 Emissions**  **Data 7.2.2.1**  **Summary of Major Studies and Emissions** In the evaluation of the emissions from pneumatic pumps and the potential options available to reduce these emissions, numerous studies were consulted. Table 7 - 1 lists these references with an indication of the ty pe of relevant information contained in each reference. In addition to these sources, we evaluated the peer reviewer and public comments received on the EPA’s white paper, “Oil and Natural Gas Sector Pneumatic Devices.” 104

103 Radian International LLC . Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic Devices . Prepared for the Gas Research Institute and Environmental Protection Agency. EPA - 600/R - 96 - 080k. June 1996. 104 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Pneumatic Devices . Report for Oil and Natural Gas Sector Pneumatic Devices Revie w Panel . Office of Air Quality Planning and Standards (OAQPS). April 2014.***E.O. 12866 Review

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7 - 5 Pneumatic Pumps **Table 7 -**  **1 . Major Studies Reviewed for Consideration of Emissions and Activity Data**  **Report Name Affiliation**  **Year of Report**  **Activity**

**Factors Emissions** 

**Data Control** 

**Options** Greenhouse Gas Reporting Programa EPA 2014 Nationwide X Inventory of Greenhouse Gas Emissions and Sinks: 1990 - 2012 b EPA 2014 Nationwide/ Regional X Methane Emissions from the Natural Gas Industryc GRI/EPA 1996 Nationwide X Methane Emissions from the Petroleum Industryd EPA 1999 Nationwide X Natural Gas STAR Programe EPA 2012 X X a. U.S. Environmental Protection Agency. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: Climate Change Division. Washington, DC. November 2014. b U.S Environmental Protection Agency. Methodology for Estimating CH 4 and CO 2 Emissions from Natural Gas Systems. Greenhouse Gas Inventory: Emission and Sinks 1990 - 2012. Washington, DC. And U.S Environmental Protection Agency. Methodology for Estimating CH 4 and CO 2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 1990 - 2012. Washington, DC. c. Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical Report. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA - 600/R - 96 - 080b. June 1996, Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 3: General Methodology. Prepared for the Gas Research Institute and Environmental Protection Agency. EP A - 600/R - 96 - 080c. June 1996. d Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 5: Activity Factors. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA - 600/R - 96 - 080e. June 1996, and Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic Devices. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA - 600/R - 96 - 080k. June 1996. e . U.S. Environmental Protection Agency. Lessons Learned: Options for Reducing Methane Emissions From Pneumatic Devices in the Natural Gas Industry. Office of Air and Radiation: Natural Gas Star. Washington, DC. February 2004. **7.2.2.2 Representative Pneumatic Pump Emissions**  For this anal ys is, the EPA consulted information in the appendices of Natural Gas STAR lessons l earned documents on pneumatic pump s , 105 , 106 , the GHGRP, the GHG Inventory , and U.S. EPA GRIReport 107 . The GHGRP and GHG Inventory use the emission factors from the U .S. EPA GRIReport. Similarly , the EPA determined that the best available emissions factors for pneumatic pumps are presented in the U.S. EPA GRI Report. The basic approach used for this anal ys is was to first approximate methane emissions from the average pneumatic pump in each industry segment and then estimate VOC and HAP

105 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 20 04. 106 U.S. Environmental Protection Agency. Pro Fact Sheet No. 301. Convert Pneumatics to Mechanical Controls . Office of Air and Radiation: Natural Gas Star. Washington, DC. September 2004. 107 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).***E.O. 12866 Review

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7 - 6 Pneumatic Pumps emissions using the gas composition factors from the 2011 Gas Composition Memorandum. The specific gas composition ratios used for this anal ys is were 0.278 lbs VOC per pound methane in the production and processing segments, and 0.0277 lbs VOC per pound methane in the transmission segment. Table 7 - 2 summarizes the estimated average bleed emission factors for a representative pneumatic pump for the production and processing segments for b oth methane and VOC. **Table 7 -**  **2 . Average Bleed Emission Estimates per Pneumatic Device**  **Segment/Pump Type**  **Emission Factor**

**Methane (scf/**  **day )**  **a Emission Factor** 

**Methane (Mcf/yr)**  **b Emission Factor** 

**Methane (tpy)**  **c Emission Factor** 

**VOC (tpy)**  **d Production**  Diaphragm 446 163 3.46 0.96 Piston 48.9 18 0.38 0.11 **Processing** Small Diaphragm 446 163 3.46 0.96 Medium Diaphragm 446 163 3.46 0.96 Large Diaphragm 446 163 3.46 0.96 Small Piston 48.9 18 0.38 0.11 Medium Piston 48.9 18 0.38 0.11 Large Piston 48.9 18 0.38 0.11 a. Data Source: EPA/GRI. Methane Emissions from the Natural Gas Industry, Volume 13: Chemical Injection Pumps. June 1996 (EPA - 600/R - 96 - 080m), Sections 5.1

– Diaphragm Pumps and 5.2

– Piston Pumps. b. Assumes 365 days/yr operation in natural gas production and processing. c. Assumes density of methane is 19.26 g/scf. d. Assumes 0.278 VO C content per pound of methane. 

### 7.3 **Available Controls and Regulatory A**  **pproaches 7.3.1**  **Available VOC Emission Control Options**  Natural gas - driven pneumatic pumps emit VOC emissions as part of their normal operation. Depending on the ty pe of pump and the constraints of the location, companies can utilize a variety

of technologies that have been developed over the years. In situations where the replacement of natural gas - driven pumps with electric, solar and instrument air pumps is not feasible, emissions can be captured via a VRU or routed to a combustion device. Sections 7.3.1.1 and 7.3.1.2 discuss the control of VOC emis sions by replacing natural gas - driven pumps with solar pumps and electric pumps. Section 7.3.1.3 discusses the use of an***E.O. 12866 Review

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7 - 7 Pneumatic Pumps instrument air sy stem to drive the pneumatic pump in order to eliminate VOC emissions. L astly , section 7.3.1.4 discusses reducing VOC e missions by routing emissions from the pump to a combustion device, and section 7.3.1.5 discusses capturing VOC emissions using a VRU. **7.3.1.1 Solar Pumps**  Description Solar pumps provide the same functionali ty as natural gas - driven pumps and can be utilized at remote sites where electricity is not available. However, peer review comments received on the EPA’s white paper “Oil and Natural Gas Sector Pneumatic Devices” noted that they predominantly

operated solar - powered pneumatic pumps for chemical in jection and the pumps failed as earl y as after two to three cloudy day s due to insufficient battery charge. 108 When solar pumps are properly charged, a solar - charged DC pump can handle a range of throughputs up to 100 gallons per day with maximum injection p ressure around 3,000 psig and have no VOC emissions. Converting natural gas - driven chemical pumps can reduce methane emissions by

an estimated 3.46 tpy per diaphragm pump and 0.38 tpy per piston pump for all segments of the ONG source category . 109 Based on the gas composition for natural gas in the production segment, we estimate that replacement of a pneumatic pump with a solar- powered pump will reduce VOC emissions by 0.96 tpy per diaphragm pump and 0.11 tpy for a piston pump. Control Effectiveness Replaci ng a gas - driven pump with a solar pump can result in 100 percent reduction in emissions and is feasible in regions where there is sufficient sunlight to power the pump, and backup power is not required. Although as stated above solar- powered pumps are capable of pumping up to 100 gallons per day , they are typically used for low volume applications to inject methanol or corrosion inhibitors into a well with typical volumes ranging from 6 to 8 gallons per day . In addition to the low volume pumps, large vo lume pumps used to replace natural gas assisted circulation pumps for glycol dehydrators can also be converted to solar. Cost Impacts

108 Reese, Carrie, Environmental Compliance Manager. Comments on the Oil and Natural Gas Sector Pneumatic Devices. Pioneer Natural Resources. 109 U.S. Environmental Protection Agency. PRO Fact Sheet No. 202. Convert Natural Gas -Driven Chemical Pumps . Available online - http://www.epa.gov/gasstar/documents/convertgasdrivenchemicalpumpstoinstrumentair.pdf .***E.O. 12866 Review

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7 - 8 Pneumatic Pumps The primary

costs associated with conversion to solar pumps are the initial capital expenditures. Solar pumps generall y have low maintenance costs which are ty pically lower than natural gas - driven pump maintenance costs. The cost being attributed to the replacement of pneumatic pumps with solar powered pumps includes the capital cost of the pump and its associated operating c osts. The operating costs are estimated to be 10 percent of the capital costs. Based on the Natural Gas STAR document, “PRO Fact Sheet: Convert Natural Gas - Driven Chemical Pumps,” 110 the capital (purchase) cost for a solar - powered electric pump is approximat ely

$2,000 with solar panels having a lifespan of 15 years and electric motors lasting 5 years. The total capital costs, including installation and labor is $2,227 (2012 dollars). We estimate there would be no additional annual operating costs for solar pumps above and beyond that of ordinary

field personnel duties. Annualized over the life of the pump at a 7 percent discount rate, the annualized cost s of replacing pneumatic pump with a solar pump are $317. In addition, the use of solar pumps will have savings realized from the natural gas not released. We estimate that each diaphragm pump replaced will save 197 Mcf per ye ar of natural gas from being emitted and each piston pump will have a natural gas savings of 22 Mcf per ye ar. The value of the natural gas saved based on $4.00 per Mcf would be $786 per year per diaphragm pump and $87 per ye ar per piston pump. **7.3.1.2 Electric Pumps**  Description Electric pumps provide the same functionality as natural gas - driven pumps, and are onl y restricted b y the use of re liable power. Electric pumps have no VOC emissions, and converting a natural gas - driven pneumatic pump to an electric pump can reduce VOC emissions by an estimated 0.96 tpy per diaphragm pump and 0.11 tpy per piston pump. Based on the gas composition for n atural gas in the production segment, we estimate that replacement of a pneumatic pump with an electric pump will also reduce methane emissions by 3.46 tpy per diaphragm pump and 0.38 tpy for a piston pump. Control Effectiveness

110 U.S. Environmental Protection Agency. PRO Fact Sheet No. 202. Convert Natural Gas -Driven Chemical Pumps . Available online - http://www.epa.gov/gasstar/documents/convertgasdrivenchemicalpumpstoinstrumentair.pdf .***E.O. 12866 Review

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7 - 9 Pneumatic Pumps Replacing a natural gas - driven pump with an electric pump requires the availability of a consistent and reliable source of electricity . These pumps are, therefore, more common at processing plants or large dehydration facilities that have access to reliabl e electric power. Cost Impacts The primary

costs associated with converting natural gas - driven pumps to electric pumps are the initial capital expenditures, installation and ongoing operation and maintenance. Based on the Natural Gas STAR document, “PRO F act Sheet: Convert Natural Gas - Driven Chemical Pumps” 111 the cost of an electric pump to replace a diaphragm pump is $4,647 and to replace a piston pump is $1,819 in 2012 dollars depending on the horsepower of the unit. 112 The annual operating costs for an ele ctric pump are es timated to be $293. Based on the se costs annualized over the life expectancy

of the pump at a 7 percent discount rate, the annualized cost s for an electric pump to replace a diaphragm pump are $954, and $506 to replace a piston pump. In ad dition, the use of electric pumps will have savings realized from the natural gas not released. We estimate that each diaphragm pump replaced will save 197 Mcf per ye ar of natural gas from being emitted and each piston pump will have a natural gas savings of 22 Mcf per ye ar. The value of the natural gas saved based on $4.00 per Mcf would be $786 per year per diaphragm pump and $72 per ye ar per piston pump. **7.3.1.3 Instrument Air System**  Description Instrument air s ys tems require a compressor, power source, dehydrator, and volume tank. The same pneumatic pumps can be used for natural gas and compressed air, without altering any of the parts of the pneumatic pump, but instrument air eliminates the emis sions of natural gas. All facilities that have access to an adequate and reliable source of electricity can install an instrument air sy stem. The following, taken from the Natural Gas STAR document, “PRO Fact Sheet: Convert Gas Pneumatic Controls to Instrument Air,” 113 describes the major components of an instrument air s ys tem:

111 Ibid. 112 U.S. Environmental Protection Ag ency. Lessons Learned . Replacing Gas - Assisted Glycol Pumps with Electric Pumps . Available online - http://www.epa.gov/gasstar/documents/ll_glycol_pumps3.pdf . 113 U.S. Environmental Protection Agency . Lessons Learned from Natural Gas STAR Partners . Convert Gas Pneumatic Controls to Instrument Air . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. 2006.***E.O. 12866 Review

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7 - 10 Pneumatic Pumps 1) Compressors used for instrument air delivery are available in various types and sizes, from rotary

screw (centrifugal) compressors to positive displacement (reciprocating piston) ty pes . The size of the compressor depends on the size of the facility , the number of control devices operated by the system, and the ty

pical bleed rates of these devices. The compressor is usually driven b y an electric motor that turns on and off, depending on the pressure in the volume tank. For reliability , a full spare compressor is normally installed. 2) A critical component of the instrument air control sy stem is the power source required to operate the compressor. Because high - pressure natural gas is abundant and readil y available, natural gas - driven pneumatic s ys tems can run uninterrupted on a 24 - hour, 7 - day per week schedule. The reliability of an instrument air sy stem, however, depends on the reliability

of the compressor and electric power suppl y. Most large natural gas plants have either an existing electric power supply or have their own power generation sy stem. For smaller facilities and remote locations, however, a reliable source of electric power can be difficult to assure. In some instances, solar - p owered batteryoperated air compressors can be feasible for remote locations, which would both reduce VOC emissions and energy consumption. Small natural gas - powered fuel cells are also being developed. 3) Deh ydrators, or air dryers, are an integral part of the instrument air compressor sy stem. Water vapor present in atmospheric air condenses when the air is pressurized and cooled, and can cause a number of problems to these sy stems, including corrosion of the instrument parts and blockage of instrument air piping and controller orifices. 4) The volume tank holds enough air to allow the pneumatic control s ys tem to have an uninterrupted supply

of high pressure air without having to run the air compressor continuously . The volume tank allows a large withdrawal of compressed air for a short time, such as for a motor starter, pneumatic pump, or pneumatic tools, without affecting the process control functions. Control Effectiveness Instrument air eliminates all emissions from natural gas - driven pneumatic pumps, but can only be utilized in location s with sufficient and reliable electrical power. Furthermore, instrument air sy stems are more economical and therefore more common at facilities with a high***E.O. 12866 Review

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7 - 11 Pneumatic Pumps concentration of pneumatic devices and where an operator can ensure the sy stem is properly function ing. 114 Because all emissions can be avoided by converting natural gas - driven chemical pumps to instrument air, methane emissions can be reduced b y an estimated 3.46 tpy per diaphragm pump and 0.38 tpy per piston pump. Based on the gas composition for natural gas in the production segment, we estimate that replacement of a pneumatic pump converted to instrument air will reduce VOC emissions by 0.96 tpy per diaphragm pump and 0.11 tpy for a piston pump. Cost Impacts As stated previousl y, instrument air conver sions require a compressor with a capacity based on the number of control loops at the location. The compressor size is equivalent to the volume of gas used b y the control loops after adjusting for gas losses during drying, plus any utility air necessary

at the facility. This volume can either be calculated via a meter or utilizing a rule of thumb of one cubic foot per minute (cfm) of instrument air per control loop. 115 The costs associated with instrument air sy stems are primaril y capital costs for the comp ressor(s), air dryer and the volume tank, but also include operational costs for electricity to drive the compressor motor. Other components of the instrument air sy stem including piping, control instruments and valve actuators would already be in place fo r a gas sy stem. We assume that existing processing plants have an instrument air sy stem in place, including backup s ys tems, and that the cost of increasing air load on the s ys tem would be confined to the incremental cost associated with upgrading or replac ing the compressor and connecting the pumps to the sy stem. The size of the compressor required would depend on the additional air load required for the instrument air sy stem to handle the pneumatic pumps. Table 7 - 3 summarizes cost estimates to replace vari ous size compressors in an existing instrument air sy stem. **7.3.1.4 Route Emissions to a New or Existing Combustion Device**  Description Combustion devices can generall y reduce 95 percent of the emissions routed to it. Combustion requires a reliable ignition source where the average gas consumption per pilot 114 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Convert Gas Pneumatic Controls to Instrument Air . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. 2006. 115 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. October 2006.***E.O. 12866 Review

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7 - 12 Pneumatic Pumps burner is 70 scf per hour. 116 Ty pical combustion devices used in the ONG source category to control VOC emissions are discussed in greater detail in section 4.3.1.2 of c hapter 4 of this document. It is assumed that most processing plants and large dehydration facilities have at least one existing combustion device on - site . **T able 7**  **- 3**  **. Cost of Compressor Replacement for Existing Instrument Air System Type of Pump**  **Size**

**Option Total**  **Capital Cost s** 

**($2012) Annualized** 

**Cost Total O&M** 

**($2012) Annualized with** 

**Operating Costs** Diaphragm Small $5,999 $854 $9,197 $10,051 Diaphragm Medium $29,989 $4,270 $28,002 $32,271 Diaphragm Large $52,779 $7,515 $64,880 $72,394 Piston Small $5,999 $854 $9,197 $10,051 Piston Medium $29,989 $4,270 $28,002 $32,271 Piston Large $52,779 $7,515 $64,880 $72,394 C ontrol Effectiveness Routing emissions from a natural gas - driven pump to an existing combustion device, or a newly installed combustion device does not reduce the volume of natural gas discharged from the pump, but rather combusts the gas. Based on the gas composition for natural gas in the production segment, we estimated that routing emissions to a combustion device would reduce VOC emissions by

an estimated 0.91 tpy per diaphragm pump and 0.1 tpy for a piston pump.

116 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners . Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry . Office of Air and Radiation: Natural Gas STAR Program. Washington, DC. October 2006.***E.O. 12866 Review

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7 - 13 Pneumatic Pumps Cost Impacts Routing natural gas to an existing combustion device or installing a new combustion device have associated capital costs and operating costs. Based on costs for a combustion device provided in the 2011 NSPS TSD, the capital costs for installing a new combustion device to control emissions are estimat ed to cost $32,301 in 2008 dollars. 117 Escalating these costs to 2012 dollars, the estimated capital costs for installing a new combustion device are $34,250 and the annual operating costs are $17,001. Based on the life expectancy for a combustion device, we estimate the annualized cost s of installing a new combustion device to be approximately $21,877, and the annualized cost s of routing emissions to an existing combustion device to be $285, using a 7 percent discount rate. Because the natural gas captured is combusted there is no gas savings associated with the use of a combustion device to reduce VOC emissions. Table 7 - 4 pres ents the estimated VOC cost of control for emission reductions from routing natural gas driven pump emissions to an existing combustion device, and Table 7 - 5 presents the cost of control for routing natural gas - driven pump emissions to a new combustion dev ice. **Table 7 -**  **4 . VOC Cost of Control for Routing Natural Gas**  **- Driven Pump Emissions to an**  **Existing Combustion Device Pump Type/**  **Segment VOC Emission** 

**Reductions (tpy/pump)**  **Annualized Cost s**  **($2012) VOC Cost of** 

**Control ($2012/ton) Diaphragm Pumps**  Production 0.91 $285 $312 Processing 0.91 $285 $312 **Piston Pumps** Production 0.10 $285 $2,850 Processing 0.10 $285 $2,850

117 U.S. Environmental Protection Agency. Oil and Natural Gas Secto r: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution

– Background Technical Support Document for Proposed Standards . July 2011. EPA Document Number EPA - 453/R- 11 - 002.***E.O. 12866 Review

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7 - 14 Pneumatic Pumps **Table 7 -**  **5 . VOC Cost of Control for Routing Natural Gas**  **- Driven Pump Emissions to a**  **New Combustion Device**  **Pump Type/ Segment**  **V OC Emission**  **Reductions (tpy/pump)**  **Annualized Cost s**  **($2012) VOC Cost of Control** 

**($2012/ton) Diaphragm Pumps**  Production 0.914 $21,877 $23,944 Processing 0.914 $21,877 $23,944 **Piston Pumps** Production 0.100 $21,877 $218,017 Processing 0.100 $21,877 $218,017 **7.3.1.5 Route Emissions to a Vapor Recovery Unit (VRU)**  Description Vapor recover units capture low pressure vapor streams, increase the pressure b y means of a compressor, then route the vapor stream to a process or other useful purpose. These s ys tems ty picall y include a backup compressor s ys tem to allow for shutdowns and repairs. Vapor recovery units are more economical for facilities with multiple natural gas emission sources that can be routed to the VRU. Some of these other emission sources can include tanks, dehydrators, and compressors and as a result, VRUs are more c ommon at natural gas processing plants. Vapor recovery units are discussed in greate r detail in section 4.3.1.1 of c hapter 4 of this document. Control Effectiveness Use of a vapor recovery

technology

has the potential to reduce the emissions from natural gas - drive pumps b y 100 percent if all vapor is recovered. However, the effectiveness of the natural gas capture s ys tem (ty picall y less than 100 percent) and downtime of the VRU for repairs and maintenance would reduce the overall emissions reductions and therefore, we estimate that routing emissions from a natural gas - driven pump to an existing or newl y installed VRU can reduce the natural gas emitted by approximately 95 percent, while at the same time, capturing the natural gas for beneficial use. We estimate that methane emission reductions for routing gas to a VRU to be 3.29 tpy for a diaphragm pump and 0.36 tpy for a piston pump. Based on the gas composition for natural gas in the production segment, we estimate that routing emissions to a VRU will reduce VOC emissions by 0.91 tpy per diaphragm pump and 0.1 tpy for a piston pump.***E.O. 12866 Review

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7 - 15 Pneumatic Pumps Cost Impacts Based on costs for a VRU provided in the 2011 NSPS TSD f or pneumatic pump s, the capital cost s and installation costs for a VRU was estimated to be $98,186 in 2008 dollars. 118 We estimate the capital cost s of installing a VRU to be $104,111 and the annual operation and maintenance cost to be $9,932 in 2012 dollars. The total annu alized cost s of a new VRU are estimated to be $24,755 based on a 7 percent discount rate. If a VRU is already on - site, then the additional costs for routing emissions from a pump are small, as the majority of costs are piping. We estimate the cost of routing emissions to an existing VRU to be $2,000 in 2012 dollars. The annualized cost s of routing natural gas emissions to an existing VRU are estimated to be $285 based on a 7 percent discount rate. In addition, there is potential for beneficial use of n atural gas recovered through the VRU. We estimated the annual natural gas recovered to be 187 Mcf per ye ar per diaphragm pump and 21 Mcf per ye ar per piston pump. The resulting natural gas savings is estimated to be $749 per diaphragm pump and $84 per pist on pump, per year based on a value of $4.00 per Mcf of natural gas recovered. Table 7 - 6 presents the estimated VOC cost of control for routing natural gas - driven pump emissions to an existing VRU, and Table 7 - 7 presents the estimated VOC cost of control fo r routing gas - driven pump emissions to a new VRU. **Table 7 -**  **6 . VOC Cost of Control for Routing Natural Gas**  **- Driven Pump Emissions to an**  **Existing VRU Pump Type/**  **Segment VOC**  **Emission**

**Reductions (tpy/pump)**  **Annualized Cost s** 

**($2012 )**  **VOC Cost of Control ($2012**  **/ton)**

**Without s avings**  **With s avings**  **Diaphragm Pumps** Production 0.91 $285 $312 ( $507 ) Processing 0.91 $285 $312 ( $507 ) **Piston Pumps** Production 0.10 $285 $2,840 $2,007 Processing 0.10 $285 $2 ,840 $2 ,007

118 U.S. Environmental Protection Agency. Oi l and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distrib ution

– Background Technical Support Document for Proposed Standards . July 2011 . E PA Document Number EPA - 453/R- 11 - 002 .***E.O. 12866 Review

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7 - 16 Pneumatic Pumps **Table 7 -**  **7 . VOC Cost of Control for Routing Natural Gas**  **- Driven Pump Emissions to a New**  **VRU Pump Type/**  **Segment VOC**  **Emission**

**Reductions (tpy/pump)**  **Annualized Cost s** 

**( $2012**  **) VOC Cost of Control (**  **$2012 /ton)** 

**Without s avings**  **With s avings**  **Diaphragm Pumps** Production 0.91 $ 24,755 $ 27,094 $ 26,274 Processing 0.91 $ 24,755 $ 27,094 $ 26,274 **Piston Pumps** Production 0.10 $ 24,755 $ 246,697 $ 245,860 Processing 0.10 $ 24,755 $ 246,697 $ 245,860 **7.3.2 Existing Federal, State and Local Regulations**  **7.3.2.1 Federal Regulations that Specifically Require Control of VOC**  **Emissions** The EPA has proposed federal requirements for natural gas - driven pneumatic pumps under 40 CFR part 60, subpart OOOOa (subpart OOOOa). Under the proposed subpart OOOOa, each natural gas - driven chemical/methanol and diaphragm pump located at a natural gas processing plant must have a natural gas bleed rate of zero scfh, and each natural gas - driven chemical/methanol and diaphragm pump located outside of a natural gas processing plant must reduce VOC emissions by 95 percent or greater when there is an control device already in place at the facility, or when a control device is installed at an existing facility. **7.3 .2.2**  **State and Local Regulations that Specifically Require Control of VOC** 

**Emissions** States may

have permitting restrictions on VOC emissions that may apply to an emissions source as a result of an operating, NSR NA, or PSD permit (e.g., on a case - by- case basis) based on air quality maintenance or improvement goals of an area. Permits specify what construction is allowed, what emission limits must be me t, and often how the source may be operated. To assure that sources follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements. Permits specify what construction is allowed, what emission limits must be met, and often how the source must be operated. To assure that sources***E.O. 12866 Review

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7 - 17 Pneumatic Pumps follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements. At least one state (W yoming) requires emissions associated with the discharge streams from all natural gas - operated pneumatic pumps be controlled by at least 98 percent or routed into a closed loop s ys tem (e.g., sales line, collection line, fuel suppl y line). Several states also have registration rules for controlling fugitive VOC emis sions (which may include fugitive emissions from pneumatic pumps). 

### 7.4 Recommended RA **CT Level of Control** Based on our evaluation of available data obtained in the development of the 2015 NSPS proposal and peer review comments received on the EPA’s white paper “Oil and Natural Gas Sector Pneumatic Devices,” and considering that Wyoming already requires emissio ns associated with the discharge streams from all natural gas - operated pneumatic pumps to be controlled by

at least 98 percent or routed into a closed loop sy stem (e.g., sales line, collection line, fuel supply

line), we recommend that VOC emissions from i ndividual natural gas - driven chemical/methanol and diaphragm pump located from the wellsite to the point of custody transfer to the natural gas transmission and storage segment and at a natural gas processing plant be controlled b y RACT. Our recommended RACT for existing individual gas - driven chemical/methanol and diaphragm pumps located from the wellhead to the point of custody transfer to the transmission and storage segment, using natural gas emissions as a surrogate for VOC emissions, is to reduce natural gas emissions by

95 percent b y routing emissions to a control device where there is an existing control device available on - site. If there is an existing VRU available on - site, then we recommend RACT to be reducing natural gas emissions by 95 percent b y using the VRU to route emissions to a process. If a control device is subsequently installed at the facility

where the pump is located, then the owner or operator would have to route the natural gas emission stream from the pump to the newly

installed co ntrol device. Our rationale for selecting 95 percent control when there is an existing control device is that , a s presented in Table 7 - 4 in section 7.3.1.4 of this c hapter, the VOC cost of control when an existing combustion device is available on - site was estimated to be $312/ton for diaphragm pumps and $2,850/ton for piston pumps. As presented in Table 7 - 6 in section 7.3.1.5 of this c hapter, the VOC cost of control when an existing VRU is***E.O. 12866 Review

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7 - 18 Pneumatic Pumps available on - site was estimated to be a cost savings for diaphragm pumps and $2,007/ton for piston pumps. We consider these costs to be reasonable. Requiring control where there is not an existing control device on - site was not considered to be reasonable available technology , and the costs per ton of VOC reduced are esti mated at greater than $20,000 per ton of VOC reduced for diaphragm pumps and over $200,000 per ton of VOC reduced for piston pumps. Our recommended RACT for existing individual chemical/methanol and diaphragm pump located at natural gas processing plants i s that they have a natural gas bleed rate of zero scfh (unless there are functional needs, including but not limited to response time, safety and positive actuation, requiring a bleed rate greater than zero scfh) . Our rationale for selecting a natural blee d rate of zero scfh (with functional and safety exceptions) for our recommended RACT is based on the ability of most large natural gas processing plants to install and utilize an instrument air sy stem. As discus sed in section 7.3.1.3 of this c hapter, b y us ing an instrument air sy stem, compressed air may be substituted for natural gas in pneumatic s ystems without altering any of the parts of the pneumatic sy stem. Therefore, the use of instrument air eliminates natural gas and VOC emissions from each gas - driv en pneumatic pump and supports a natural gas rate bleed rate of zero scfh. In summary , we recommend the following RACT for pneumatic pumps in the ONG source category : 1) Each Natural Gas - Driven Chemical/Methanol and Diaphragm Pump L ocated at a Natural Gas Processing Plant : Each pump must have a natural gas emissions of zero. 2) Each Natural Gas - Driven Chemical/Methanol and Diaphragm Pump L ocated From the Wellhead to the Natural Gas Processing Plant : I f there is a control device located on - site of the location of the pump, using natural gas as a surrogate for VOC, you must reduce natural gas emissions by 95 percent by

routing to the control device or to a process. If a control device is subsequently added to the site where the pump is located, then the natural gas emissions from the pump must be routed to the newl y installed control device. Although sources have a choice on how they meet the RACT level of control, the technologies that will likely be used to meet the RACT level of control for each natural gas driven pneumatic pump located from the wellhead to the natural gas processing plant are either routing the natural gas emission to an on - site existing combustion device (or a subsequentl y***E.O. 12866 Review

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7 - 19 Pneumatic Pumps installed combustion device) or routing the natural gas emissions to a process using an on - site existing VRU (or a subsequently installed VRU). Similarly, the technology that will likely be used to meet the RACT level of control for each natural gas - driven chemical/methanol and diaphragm pump located at a natural gas processing plant is the use of an existing instrument air sy stem assumed to already exist on - site at natural gas processing plants. 

### 7.5 **Factors to Consider in Developing Pneumatic Pump**  **Compliance Procedures**  **7.5.1 ONG**  **Production Segment Recommendations** We recommend that regulatory agencies require each pneumatic pump be tagged with the date that the pneumatic pump is required to comply with the rule (as established by the regulating agency) that allows traceability . We also suggest that regulatory agenci es require owners and operators of pneumatic pumps to maintain records that document the location and manufacturer’s specifications of each pneumatic pump that are tied to the identification information of each pump. The owner or operator should also be re quired to document deviations in cases where a pneumatic pump was not operated in compliance with RACT. We also recommend that regulatory agencies require owners and operators to submit annual reports that include the records of deviations that occurred during the reporting period. The Appendix to this document presents example model rule language that incorporates compliance elements recommended in this section that states may choose to use in whole or in part when implementing RACT. **7.5.2 Natural Gas Proc**  **essing Segment Recommendations** We suggest that regulatory agencies require each pneumatic pump be tagged with the date that the pneumatic pump is required to comply with the rule (as established by the regulating agency) that allows traceability . We also recommend that regulatory agencies require owners and operators of pneumatic pumps to maintain records that document the location and manufacturer’s specifications of each pneumatic controller that are tied to the identification information of each pump. Th e owner or operator should also be required to document deviations in cases where a pneumatic pump was not operated in compliance with RACT. We***E.O. 12866 Review

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7 - 20 Pneumatic Pumps also recommend that regulatory agencies require owners and operators to submit annual reports that include the records of deviations that occurred during the reporting period. The Appendix to this document presents example model rule language that incorporates compliance elements recommended in this section that States may choose to use in whole or in part when impl ementing RACT.***E.O. 12866 Review

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8 - 1 Equipment Component Leaks 

### 8.0 **EQUIPMENT COMPONENT LEA KS FROM ONSHORE NATURA**  **L GA** **S PROCESSING PLA NTS**  This chapter presents the causes for equipment component leaks from onshore natural gas processing plants, and provides emissions estimates for “model” facilities in the processing segment of the ONG source category . Methods that are designed to reduce equ ipment leak emissions are presented, along with our recommended RACT and the associated VOC emission reductions and cost impacts for equipment component leaks from onshore natural gas processing plants. 

### 8.1 **Ap plicability**  For purposes of this guideline , th e emissions and emissions controls discussed herein would apply

to the group of all equipment (except compressors) within a process unit located at an onshore natural gas processing plant in VOC service or in wet gas service. For a piece of equipment to be considered not in VOC service, it must be determined that the VOC content can be reasonabl y expected never to exceed 10.0 percent by weight at or greater than 300 hours per ye ar. For a piece of equipment to be considered in wet gas service, the piece of e quipment must contain or contact the field gas before the extraction step at a gas processing plant. Equipment is defined as each pump, pressure relief device, open - ended valve or line, valve, and flange or other connector that is in VOC service or in wet gas service 

### 8.2 **Process Description and Emission Sources 8.2.1**  **Process Description** Natural gas processing involves the removal of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. The ty pes of process equipment used to separate the liquids are separators, gl ycol deh ydrators, and amine treaters. In addition, centrifugal and/or reciprocating compressors are used to pressurize and move the natural gas from the processing facility to the transmissi on stations. There are several potential sources of equipment leak emissions at natural gas processing plants. Components such as pumps, pressure relief devices, valves, flanges, and other connectors are potential sources that can leak due to seal failure. Other sources, such as open - ended lines and valves may

leak for reasons other than faulty seals. In addition, corrosion of welded***E.O. 12866 Review

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8 - 2 Equipment Component Leaks connections, flanges, and valves may also be a cause of equipment leak emissions. The following sub - sections describe potenti al equipment leak sources and the magnitude of the VOC emissions from natural gas processing plants. Due to the large number of valves, pumps, and other components within natural gas processing plants, total equipment leak VOC emissions from these components can be significant (c hapter 2.2 of the 1983 CTG 119 presents a description of these equipment components and is not repeated here). **8.2.2 Equipment Leak Emission Data and Emissions Factors**  **8.2.2.1 Summary of Major Studies and Emission Factors** The 2012 NS PS STSD evaluated emissions data from equipment leaks collected from chemical manufacturing and petroleum production to assist in the development of control strategies for reducing VOC emission from these sources. 120 , 121 , 122 Table 8 - 1 presents a list of the studies consulted along with an indication of the ty pe of information contained in the study . In addition to these sources, we evaluated the peer reviewer and public comments received on the EPA’s white paper, “Oil and Natural Gas Sector Leaks.” 123 **Table 8 -**  **1 . Major Studies Reviewed for Consideration of Emissions and Activity Data**  **Report Name Affiliation**  **Year of Report**  **Activity**

**Factors Emissions** 

**Data Control** 

**Options** Protocol for Equipment Leak Emission Estimates a EPA 1995 None X X Methane Emissions from the Natural Gas Industry: Equipment Leaks b GRI/EPA 1996 Nationwide X X

119 U.S. Environmenta l Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC, 27711. Guideline Series. Control of Volatile Organic Compound Equipment Leaks from Natural Gas/Gasoline Processing Plants. December 1983. EPA - 450/3 - 83 - 007 120 Memor andum from David Randall, RTI and Karen Schaffner, RTI to Randy McDonald, U.S. Environmental Protection Agency. Control Options and Impacts for Equipment Leaks: Chemical Manufacturing Area Source Standards . September 2, 2008. 121 Memorandum from Kristen Parri sh, RTI and David Randall, RTI to Karen Rackley, U.S. Environmental Protection Agency. Final Impacts for Regulatory Options for Equipment Leaks of VOC on SOCMI. October 30, 2007. 122 Memorandum from Kristen Parrish, RTI, David Randall, RTI, and Jeff Coburn, RTI to Karen Rackley, U.S. Environmental Protection Agency. Final Impacts for Regulatory Options for Equipment Leaks of VOC in Petroleum Refineries . October 30, 2007. 123 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Leaks . Report for Oil a nd Natural Gas Sector Leaks Review Panel . Office of Air Quality Planning and Standards (OAQPS). April 2014.***E.O. 12866 Review

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8 - 3 Equipment Component Leaks

**Report Name Affiliation**  **Year of Report**  **Activity**

**Factors Emissions** 

**Data Control** 

**Options** Greenhouse Gas Reporting Programc EPA 2010 Nationwide X X Inventory of Greenhouse Gas Emissions and Sinks: 1990 - 2008 d EPA 2010 Nationwide X Methane Emissions from the Natural Gas Industrye,f,g,h GRI/EPA 1996 Nationwide X X Methane Emissions from the U.S. Petroleum Industryi EPA 1996 Nationwide X Methane Emissions from the US Petroleum Industry j EPA 1999 Nationwide X Oil and Gas Emission Inventories for Western States k Western Regional Air Partnership 2005 Regional X X Recommendations for Improvements to the Central States Regional Air Partnership's Oil and Gas Emission Inventories l Central States Regional Air Partnership 2008 Regional X X Oil and Gas Producing Industry in Your State m Independent Petroleum Association of America 2009 Nationwide Emissions from Natural Gas Production in the Barnett Shale and Opportunities for Cost - effective Improvements n Environmental Defense Fund 2009 Regional X X Emissions from oil and Natural Gas Production Facilities o Texas Commission for Environmental Quality 2007 Regional X X Petroleum and Natural Gas Statistical Datap U.S. Energy Information Administration 2007 -

2009 Nationwide Preferred and Alternative Methods for Estimating Air Emissions from Oil and Gas Field Production and Processing Operations q EPA 1999 X X

a. U.S. Environmental Protection Agency, 1995. Protocol for Equipment Leak Emission Estimates. Office of Air Quality Pla nning and Standards. Research Triangle Park, NC. November 1995. EP A - 453/R - 95 - 017. Available at http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf . b. Gas Research Inst itute (GRI)/U.S. Environmental Protection Agency. Research and Development, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. June 1996 (EPA - 600/R - 96 - 080h).***E.O. 12866 Review

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8 - 4 Equipment Component Leaks c. U.S. Environmental Protection Agency. 2013b. Petroleum and Natural Gas Systems: 2012 Data Summary . Greenhouse Gas Reporting Program. October 2013. d. U.S. Environmental Protection Agency (EPA) . 2010. Inventory of Greenhouse Gas Emissions and Sinks: 1990 - 2018. Climate Change Division, Washington, DC. e. Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical Report . Prepared for the Gas Research Institute and Environmental Protection Agency.EPA - 600/R - 96 - 080b. June 1996. f. Radian International LLC . Methane Emissions from the Natural Gas Industry, Vol. 3: General Methodology . P repared for the Gas Research Institute and Environmental Protection Agency.EPA - 600/R - 96 - 080c. June 1996. g. Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 5: Activity Factors . Prepared for the Gas Research Institute and Environmental Protection Agency.EPA - 600/R - 96 - 080e. June 1996. h. Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 6: Vented and Combustion Source Summary Emissions . Prepared for the Gas Rese arch Institute and Environmental Protection Agency.EPA - 600/R - 96 - 080f. June 1996. i. Radian International LLC, Methane Emissions from the U.S. Petroleum Industry , draft report for the U.S. Environmental Protection Agency, June 14, 1996. j. ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry . Prepared for the U.S. Environmental Protection Agency. 1999. k. ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States . Prepared for Western Governors’ Associati on. December 27, 2005. l. ENVIRON International Corporation. Recommendations for Improvements to the Central States Regional Air Partnership's Oil and Gas Emission Inventories Prepared for Central States Regional Air Partnership . November 2008. m. Independent Petroleum Association of America. Oil and Gas Producing Industry in Your State . n. Armendariz, Al . Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost- Effective Improvements . Prepared for Environmental De fense Fund. January 2009. o. Eastern Research Group, Inc. Emissions from Oil and Gas Production Facilities . Prepared for the Texas Commission on Environmental Quality. August 31, 2007. p. U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price . Energy Information Administration. Natural Gas Navigator. Retrieved online on 12 Dec 2010 at http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm . q Eastern Research Group, Inc . Preferred and Alternative Methods for Estimating Air Emissions from Oil and Gas Field Production and Processing Operation . Prepared for the U.S. Environmental Protection Agency. September 1999. **8.2.2.2 Natural Gas Processing Model Plant** Natural gas process ing plants can consist of a variety of combinations of process equipment and components. In order to conduct analy ses to be used in evaluating potential options to reduce emissions from leaking equipment, the 2011 NSPS TSD and the 2012 NSPS STSD used a mod el plant approach. In formation related to equipment counts were obtained from a natural gas industry report. 124 This document provided average equipment counts for gas production and gas processing segments. These average counts were used to develop a model plant. These equipment counts are consistent with those contained in the EPA’s anal ys is to estimate methane emissions conducted in support of the GHGRP. The onshore natural gas processing model plant is discussed in the following section. A summary of the model plant production component counts for a gas processing facility is provided in Table 8 - 2.

124 U.S. Environmental Protection Agency/GRI. Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks . Table 4 - 13, June 1996. (EPA - 600/R - 96 - 080h)***E.O. 12866 Review

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8 - 5 Equipment Component Leaks

**Table 8 -**  **2 .**  **Component Counts for Natural Gas Processing Model Plant**

**Component Component Count** 

**(non -**  **compressor components)**  Valves 1,392 Connectors 4,392 Open - Ended Li nes (OEL) 134 Pressure Relief Valve (PRV) 29 Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4 - 13, June 1996. (EPA - 600/R - 96 - 080h) **8.2.2.3 Natural Gas Processing**  **Model Plant Emissions** Overview of Approach The EPA gathered equipment leak data and cost information for the development of the Uniform Standards for Equipment Leaks. These Uniform Standards data were used to estimate baseline emissions for a natural gas processing model plant for the 2012 NSPS STSD and provide the baseline and controlled emission options for processing plants presented in this guideline . 125 , 126 Th e baselin e emissions were defined as being equiv alent t o a 40 CFR part 60, s u bpart VV (subpart VV) leak detection and repair (LDAR) program , which represent s t h e sam e set o f require m ent s that app ly t o natural ga s proce s sin g plant s under 4 0 CFR part 60 , subpart KKK (subpart KKK). The 2012 NSPS requires the implementation of 40 CFR part 60, subpart VVa (subpart VVa) and currently applies to natural gas processing plants constructed or modified after August 23, 2011. It is assumed that natural gas processing plants constructed or mo dified on or before August 23, 2011 currentl y still comply with subpart KKK, which is similar to the control level of subpart VV. We evaluated requiring a similar subpart VVa level of control to these plants as was required under the 2012 NSPS. We used leak frequ enc y data (refer s t o th e esti m ate d percentag e of equip m ent tha t wil l b e foun d leakin g at a gi ven leak definition) t o 125 Me morandum fr o m Cindy Hanc y , RT I International to Jodi Ho ward, EPA/OAQPS. Anal y s is ofEm ission Reduction Techniq ues for Equi pm ent Leaks . December 21, 20 1 1. 126 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New Source Performance Standards . April 2012. EPA Docket Number EPA - HQ - OAR 2010 - 0505 - 4550.***E.O. 12866 Review

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8 - 6 Equipment Component Leaks calculat e emissio n esti m ate s , in addition to several other so u rce s of information (inclu ding th e Protoco l fo r Equip m ent Leak Emi ssion s Esti m ate s an d in d ustry data) . 127 Table 8 - 3 provides a summary of the equipment leak frequency data used for the natural gas processing model plant. Emission factor s are th e esti m ate d leak rate s for an equip m ent ty p e at a given leak definitio n an d are nor m all y given in kg/hr/

p iec e o f equip m ent. Table 8 - 4 provides a summary of the VOC equipment leak emission factors representing the subpart VVa level of control was used for the natural gas processing model plant .

**Table 8 -**  **3 .**  **S ummary of Equipment Leak Frequency for Natural Gas**  **LDAR P**  **r ogra**  **m a**  **Valves (percent)**  **Connectors**

**(percent)** Baseline 1.18 / 1.18 NA Valves 5.95 / 1.91 NA Connectors NA 1.70 / 0.81 NA = Not Applicable; no equipment leak frequency percent data were available . Data Source: Me morandum fro m Cindy Hanc y , RTI International to Jodi Ho ward, EP A/OAQPS, Anal y s is of Emission Reduction Techni ques for Equipment Leaks, December 21, 20 1 1, Table 5. a. The leak frequencies provided in the tables are presented as initial leak frequenc y and subsequent leak frequenc y under the subpart VVa level of control . **Table 8 -**  **4 .**  **Summary of VOC Equipment Leak Emission Factors for the Natural Gas Processing Model Plant**  **Component Uncontrolled** 

**(kg/comp -**  **hr) Baseline** 

**(kg/comp -**  **hr) a**  **Subpart VVa**

**Control Level (kg/comp**  **- hr)**  **b** Valves 3.71E - 0 4 2.24E - 0 4 8.85E - 0 5 Connectors 1.04E - 0 4 1.04E - 0 4 3.95E - 05 OEL 2.30E - 0 3 7.34E - 05 NA PRV 1.60E - 01 9.80E - 02 NA NA = Not Applicable Data Source: Me morandum fro m Cindy Hanc y , R TI International to Jodi Ho ward, EP A/OAQPS, Anal y s is of Emission Reduction Techni ques for Equipment Leaks, December 21, 20 1 1, Table 7. a. The baseline option is ass ume d to be equi valent to a subpart VV LDAR program . b. Ass umed to be equivalent to a subpart VVa LDAR program .

127 U.S. Enviro nmental Protection Agency. Pro to c ol f or E q u i p m ent Leak E

m i ss i on Es tim a tes . Nove m

ber 1 9 9 5. EP A - 4 5 3 /R- 9 5 - 0 17***E.O. 12866 Review

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8 - 7 Equipment Component Leaks 

### 8.3 **Available Controls and Regulatory A**  **pproaches 8.3.1**  **Available VOC Emission Control Options** The EPA has determined that leaking equipment, such as valves, pumps and connectors, are a significant source of VOC emissions from natural gas processing plants. The following subsections describe the techniques used to reduce emissions from these sources. **8.3.1.1 Leak Detection and Repair Program**  The most commonly

employed control technique for equipment leaks is the implementation of a LDAR program. Emission reductions from implementing a LDAR program can potentiall y reduce product losses, increase safety for workers and operators, decrease exposure of hazardous chemicals to the surrounding community, and reduce emissions fees. The elements of an effec tive LDAR program include:  Id entifying Components;  Leak Definition;  Monitoring Components;  Repairing Components; and  Recordkeeping. The primary

sources of equipment leak emissions from natural gas processing plants are valves and connectors, because these are the most prevalent components and can number in the thousands (see Table 8 - 2). The major cause of emissions from valves and connectors is a seal or gasket failure due to normal wear or improper maintenance. A leak is detected whenever the measured conc entration exceeds the threshold standard (i.e., leak definition) for the applicable regulation. Leak definitions vary by regulation, component ty pe, service (e.g., light liquid, heavy liquid, gas/vapor), and monitoring interval. Most NSPS regulations have a leak definition of 10,000 ppm, while many National Emission Standards for Hazardous Air Pollutants (NESHAP ) regulations use a 500 - ppm or 1,000 - ppm leak definition. In addition, some regulations define a leak based on visual inspections and observations ( such as fluids dripping, spraying, misting or clouding from or around components), sound (such as hissing), and smell. For many NSPS and NESHAP regulations with leak detection provisions, the primary method for monitoring to detect leaking components is EPA Reference Method 21 (40 CFR part***E.O. 12866 Review

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8 - 8 Equipment Component Leaks 60, appendix A - 7). Method 21 is a procedure used to detect VOC leaks from process eq uipment using a toxic vapor analyzer (TVA) or organic vapor anal yz er (OVA). A second method for monitoring to detect leaking components is optical gas imaging (OGI) using an infrared camera. The infrared camera may be passive or active. The passive infrared cameras scan an area to produce images of equipment leaks from a number of sources. Active infrared cameras point or aim an infrared beam at a potential source to indicate the presence of equipment leaks. The optical imaging camera can be very efficient in monitoring many components in a short amount of time. However, the optical imaging camera cannot quantify the amount or concentration of the equipment leak. Acoustic leak detectors measure the decibel readings of high frequency vibrations from the noi se of leaking fluids from equipment leaks using a stethoscope - ty pe device. The decibel reading, along with the ty pe of fluid, density , s ys tem pressure, and component ty pe can be correlated into leak rate by using algorithms developed by the instrument manu facturer. The acoustic detector does not decrease the monitoring time because components are measured separately , like the OVA or TVA monitoring. The accuracy of the measurements using the acoustic detector can also be questioned due to the number of varia bles used to determine the equipment leak emissions. In addition, other monitoring tools such as soap solution and electronic screening devices can be used to monitor process components. Other factors that can improve the efficiency of a LDAR program inclu de training programs for equipment monitoring personnel and tracking sy stems that address the cost efficiency of alternative equipment (e.g., competing brands of valves in a specific application). Subpart VVa LDAR Program One LDAR option to control VOC emi ssions from natural gas processing plant equipment leaks is the implementation of the subpart VVa LDAR program. This program is similar to the subpart VV monitoring program (whose requirements are cross - referenced in subpart KKK), but finds more leaks due to the lower leak definition, increased monitoring frequency and the addition of connectors to the components being monitored, thereby achieving better emission reductions. The subpart VVa LDAR program requires the annual monitoring of connectors using an OVA or TVA (10,000 ppm leak definition), monthly monitoring of valves (500 ppm leak definition) and requires open - ended lines and pressure relief devices to operate***E.O. 12866 Review

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8 - 9 Equipment Component Leaks with no detectable emissions (500 ppm leak definition). Additionally , the stringency of ex isting LDAR programs being implemented at natural gas processing plants can also be strengthened b y requiring the monitoring requirements in subpart VVa for each component which includes: valves, connectors, pressure relief devices and open - ended lines. De scription The subpart VVa LDAR program requires the monitoring of pumps, compressors, pressure relief devices, sampling connection sy stems, open - ended lines, valves and connectors. These components are monitored with an OVA or TVA to determine if a component is leaking and measure the concentration of the organics if the component is leaking. Connectors, valves, and pressure relief devices have a leak definition of 500 ppmv. Valves are monitored monthly, connectors are monitored annually , and open - en ded lines and pressure relief valves have no monitoring requirements, but are required to operate without any detectable emissions. Compressors are not included in this leak detection and repair option and are regulated separately . Control Effectiveness Th e control effectiveness of an LDAR program is based on the frequency of monitoring, leak definition, frequency of leaks, percentage of leaks that are repaired, and the percentage of reoccurring leaks. The control effectiveness for all of the components varies from 45 to 96 percent and is dependent on the frequency of monitoring and the leak definition. 128 Descriptions of the frequency

of monitoring and leak definition are described further below. Monitoring Frequenc y. The monitoring frequency is the number of times each component is checked for leaks over a given period of time. More frequent monitoring provides higher control effectiveness. This is because leaking components are found and repaired more quickly , which lowers the amount of emissions that are le aked to the atmosphere. Leak Definition. The leak definition describes the local VOC concentration at the surface of a leak source that indicates that a VOC emission (leak) is present. The leak definition is an instrument meter reading based on a reference compound. Decreasing the leak definition

128 U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution - Background Supplemental Technical Support Document for the Final New Source Performance Standards . April 2012. EPA Docket Number EPA - HQ - OAR 2010 - 0505 - 4550.***E.O. 12866 Review

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8 - 10 Equipment Component Leaks generall y increases the number of leaks found during a monitoring period, which generally increases the number of leaks that are repaired. The 2012 NSPS STSD calculate d incremental emission reductions fro m th e bas eli n e requirem ents (assuming that an LDAR program equivalent to the subpart VV/subpart KKK LDAR program is currently implemented at natural gas processing plants), and th e leak frequenc y an d e missio n factor s f

ro m a supporting document for th e Equipment Leak Unifor m Standard s were use d t o calculate th e e missio n reduction s and costs . The natural gas processing plant component counts (see Table 8 - 2) were obtained from a GRI/EPA document. 129 The incremental VOC emission reductions for implementing a subpart VVa leak detection and repair program (as determined in the 2012 NSPS STSD) for the natural gas processing model plant was calculated to be 13 percent. Cost Impacts Table 8 - 5 presents a s ummary of the incremental capital and annual costs and the cost of control (estimated in the 2012 NSPS STSD) from baseline (subpart VV) to implementing subpart VVa for the gas processing model plant. The costs obtained from the 2012 NSPS STSD have been converted to 2012 dollars from 2008 dollars using the Federal Reserve Economic Data GDP Price Deflater (Change in GDP: Implicit Price Deflator from 2008 to 2012 (5.69 percent). 130 **Table 8 -**  **5 .**  **Summary of the Gas Processing Model Plant VOC Cost of Control**  **for the Subpart VVa Option Annual VOC**  **Emission Reductions (tpy)**  **Capital Cost s** 

**($2012) Annual Cost**  **s**

**($2012/year) VOC Cost of Control**  **($2012/ton) Without savings**  **With**

**savings a**  4.56 $8,499 $12,959 $2,844 $ 2,010

a With savings calculated assuming the natural gas (82.9% methane) from the methane reduction has a value of $4/Mscf. The VOC/methane ratio was assumed to be 0.278.

129 GRI/EPA Research and Development. Methane Emissions from the Natural Gas Indus try; Volume 8: Equipment Leaks . June 1996. EPA - 600/R - 96 - 080h. 130 U.S. Bureau of Economic Analysis, Gross Domestic Product: Implicit Price Deflator (GDPDEF], retrieved from FRED, Federal Reserve Bank of St. Louis https://research.stlouisfed.org/fred2/series/GDPDEF March, 26, 2015.***E.O. 12866 Review

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8 - 11 Equipment Component Leaks Table 8 - 6 provides a summary of the capital and annual costs and the cost of control on a component basis for the natural gas processing model plant. **Table 8 -**  **6 .**  **Summary of the Gas Processing Component VOC Cost of Control for the Subpart VVa Option**  **Component Annual VOC** 

**Emission Reductions**  **(tpy) Capital** 

**Cost s**  **($2012) Annual**  **Cost s** 

**($2012/year) VOC Cost of Control** 

**($2012/ton) Without**  **Savings With** 

**Savings a**  Valves 1.82 $5,231 $9,280 $5,095 $4,261 Connectors 2.74 $8,374 $4,405 $1,610 $776 a With savings calculated assuming the natural gas (82.9 percent methane) from the methane reduction has a value of $4/Mscf. The VOC/methane ratio was assumed to be 0.278. **8.3.1.2 Leak Detection and Repair Program with Optical Gas Imaging** Another option to control VOC emissions is the implementation of a program that uses OGI to detect equipment leaks. This option is currently available as an alternative work practice (40 CFR part 60, subpart A) for monitoring emissions from equipment leaks in subpart VVa. The alternative work practice requires monthly monitoring of all components using OGI and an annual monitoring of all components using a Method 21 monitoring device. The Method 21 monitoring allows the facility to quantify

emissions from equipment leaks, s ince the OGI s ys tem can onl y provide the presence of the equipment leaks. A more detailed description of, and the cost of implementing LDAR with OGIprogram for the natural gas processing model plant is presented in the following paragraphs. Description Th e alternative work practice for equipment leaks in §60.18 of 40 CFR part 60, subpart A allows the use of an OGI sy stem to monitor leaks from components. This LDAR program requires monthly

monitoring and repair of components using OGI and annual monitoring of components using a Method 21 instrument. This requirement does not have a leak definition because OGI can onl y m easure the presence of a leak and not the concentration. However, this alternative work practice does not require the repair of leaks below 5 00 ppm. Compressors are not included in this LD AR option and are discussed in c hapter 5 of this document.***E.O. 12866 Review

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8 - 12 Equipment Component Leaks Effectiveness No data were found on the control effectiveness of the alternative work practice. For purposes of this anal ys is, we assumed that this option would provide the same control effectiveness as the subpart VVa monitoring program. Therefore, the control effectiv eness values for implementing an alternative work practice were assumed to be 93.6 percent for valves, 95.9 percent for connectors, 100 percent for open - ended lines, and 100 percent for pressure relief devices. Cost Impacts The 2011 NSPS TSD calculated co sts using procedures developed for estimating capital and annual costs for applyingLDAR to the Petroleum Refinery and Chemical Manufacturing industry . Costs obtained from the 2011 NSPS TSD have been converted to 2012 dollars from 2008 dollars using the Fe deral Reserve Economic Data GDP Price Deflater (Change in GDP: Implicit Price Deflator from 2008 to 2012 (5.69 percent). 131 Itwas assumed that a single OGI device and a single Method 21 monitoring device could be used at multiple locations. To calculate the shared cost of OGI and the Method 21 devices, the time required to monitor a single facility was estimated. It was assumed for gas processing facilities that the full cost of the OGI sy stem and the Method 21 monitoring device would apply to each individual plant. Assuming a 20 - day work month, the total number of facilities that could be monitored by a single OGI sy stem and Method 21 device is 80. Therefore, the shared cost of the Method 21 monitoring device was calculated to be $1,209 per site. Table 8 - 7 present s a summary of the capital and annual costs and the VOC cost of control for the natural gas processing model plant using the alternative work practice monitoring. A cost of control anal ys is on a component basis for the alternative work practice was not performed because the OGI s ys tem is intended for facility- wide monitoring.

131 U.S. Bureau of Economic Analysis, Gross Domestic Product: Implicit Price Deflator (GDPDEF), retrieved from FRED, Federal Reserve Bank of St. Louis https://research.stlouisfed.org/fred2/series/GDPDEF March, 26, 2015.***E.O. 12866 Review

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8 - 13 Equipment Component Leaks **Table 8 -**  **7 .**  **Summary of the Natural Gas Processing Model Plant VOC Cost of Control for**

**Optical Gas Imaging and Method 21 Monitoring Annual VOC**  **Emission Reductions**  **(tpy) Capital** 

**Cost s**  **($2012) Annual Cost**  **s**

**($2012/year) VOC Cost of Control** 

**($2012/ton) Without**  **Savings With** 

**Savings** 4.56 $97,787 $92,013 $20,192 $19,358 **8.3.2 Existing Federal, State and Local Regulations**  **8.3.2.1 Federal**  **Regulations that Specifically Require Control of VOC Emissions**  Federal regulations that regulate VOC emissions from equipment leaks from components at onshore natural gas processing plants include the 2012 NSPS, subpart KKK and the 1983 CTG (established a recommended RACT for VOC for onshore natural gas processing plants at a level of control equivalent to subpart KKK). **8.3.2.2 State and Local Regulations**  **that Specifically Require Control of VOC**

**Emissions** States may

have permitting restrictions on VOC emiss ions that may apply to an emissions source as a result o f an operating, NSR NA, or PSD permit (e.g., on a case - by- case basis) based on air quality maintenance or improvement goals of an area. Permits specify what construction is allowed, what emission limi ts must be met, and often how the source must be operated. To assure that sources follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements. We assume that all states currentl y regulate equipment leaks from equipment components (except compressors) at existing natural gas processing plants at the 1983 CTG and subpart VV level of control. 

### 8.4 **Recommended RACT Level of Control for Equipment Leaks from Equipment Components at Onshore Natural Gas Processing**  **Plants** As discussed in section 8.3.2 of this c hapter, existing federal and state and local regulations already require the reduction of VOC emissions using an LDAR program. The 2012 NSPS requires a 40 CFR part 60 subpart VVa LDAR monitoring program for pro cessing plants.***E.O. 12866 Review

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8 - 14 Equipment Component Leaks The 2012 NSPS reported a cost of control for natural gas processing plants to be $2,844 per ton of VOC removed for the 40 CFR part 60 subpart VVa option, and $20,192 per ton of VOC removed for the Method 21/OGI option. The option for just m onitoring just valves or connectors at the 40 CFR part 60 subpart VVa level of control was estimated to be $5,095 and $1,610 per ton of VOC removed, respectivel y. Based on costs and existing LDAR programs that are already employed at natural gas processing plants, we recommend that RACT for natural gas processing plants be the implementation of an LDAR program equivalent to what is required under 40 CFR part 60 subpart VVa for equipment components (with the exception of compressors) in VOC service. This RAC T recommendation would increase the stringency from the currently

implemented LDAR programs at most existing natural gas processing plants (that were built prior to 2012) in VOC service b y lowering the leak definitions, increasing the monitoring frequency and including additional components. The subpart VVa leak detection and repair program requires the annual monitoring of connectors using an OVA or TVA (10,000 ppm leak definition), monthly monitoring of valves (500 ppm leak definition) and requires open - ended lines and pressure relief devices to operate with no detectable emissions (500 ppm leak definition). The estimated annual incremental VOC emissions reductions for the recommended RACT for a natural gas processing plant was estimated to be 4.56 tpy (se e Table 8 - 5 of this c hapter). The annual VOC emission reductions assume a baseline level of control equivalent to the 40 CFR part 60, subpart VV LDAR program. Table 8 - 5 presents the gas processing model plant VOC cost of control for the recommended RACT. The costs assume a baseline level of control equivalent to the 40 CFR part 60, subpart VV LDAR program. The recommended RACT VOC c ost of control is estimated to be $ 2,844 per ton of VOC reduced without savings and $2,010 with savings . In summary , we recomm end the following RACT for equipment leaks at natural gas processing plants: RACT for Equipment Leaks at Natural Gas Processing Plants : We recommend the implementation of an LDAR program equivalent to what is required under 40 CFR part 60 subpart VVa for e quipment components (with the exception of compressors) in VOC service.***E.O. 12866 Review

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8 - 15 Equipment Component Leaks 

### 8.5 **Factors to Consider in Developing Equipment Component Leak Compliance Procedures**  Existing natural gas processing plants that would be subject to the recommend RACT are already sub

ject to an LDAR program and the basic elements of the LDAR program for the facility are in place. However, the LDAR program would need to be modified to increase the stringency

from the currently

implemented LDAR program by lowering the leak definitions, and to require annual monitoring of connectors using an OVA or TVA (10,000 ppm leak definition), monthly monitoring of valves (500 ppm leak definition) and to require open - ended lines and pressure relief devices to operate with no detectable emissions (500 ppm leak definition). As with the currentl y implemented LDAR program, to ensure that equipment components in VOC service that leak at natural gas processing plants are properl y monitored and repaired under the LDAR RACT requirements, we recommend that regulatory agencies specify

monitoring and equipment component repair reco rdkeeping and reporting requirements to document compliance. Monitoring intervals vary according to the applicable regulation, but are ty pically weekl y, monthly, quarterly, and ye arl y. The monitoring interval depends on the component type and periodic le ak rate for the component ty pe. For each component that is found to be leaking, the first attempt at repair should be made within a reasonable period of time, such as no later than five calendar day s after each leak is detected. First attempts at repair in clude, but are not limited to, the following best practices, where practicable and appropriate: 1) Tightening of bonnet bolts; 2) Replacement of bonnet bolts; 3) Tightening of packing gland nuts; and 4) Injection of lubricant into lubricated packing. Once the component is repaired, it should be monitored over the next several days to ensure the leak has been successfully repaired. Another method that can be used to repair a component is to replace the leaking component with a “leakless” component or other technologies. When implementing an LDAR program, we recommend that regulatory agencies consider including recordkeeping requirements that require owner/operators of subject fac ilities to maintain a list of identification numbers for all equipment subject to an equipm ent leak regulation. A list of components that are designated as “unsafe to monitor” should also be maintained with an explanation/review of conditions for the designation. Detailed schematics,***E.O. 12866 Review

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8 - 16 Equipment Component Leaks equipment design specifications (including dates and descripti ons of any changes), and piping and instrumentation diagrams should also be maintained with the results of performance testing and leak detection monitoring. The Appendix to this document presents example model rule language that incorporates compliance elements recommended in this section that States may choose to use in whole or in part when implementing RACT.***E.O. 12866 Review

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9 - 1 Fugitive Emissions 

### 9.0 **FUGITIVE EMISSIONS FROM WELL SITES A ND**  **GA THERING**  **AND BOOSTING ST**  **AT ION**  **S** Fugitive emissions from components in the ONG production segment are a source of VOC emissions. This chapter discusses the sources of fugitive emissions, and provides VOC emission estimates for well sites and gathering and boosting station s in the production segment of the ONG source category . This chapter also presents a description of programs that are designed to reduce fugitive emissions, along with costs and emission reductions. Finally , this chapter provides a discussion of our recommended RA CT and the estimated costs and emission reduction impacts for fugitive emissions from well sites and gathering and boosting station s. 

### 9.1 **Ap plicability**  For purposes of this guideline , the emissions and programs to control emissions discussed herein would appl y to the collection of fugitive emissions components at a well site, and the collection of fugitive emissions components at a gathering and boosting station . Fugitive emissions, for the purposes of applicability of this guideline , means those emissions from a stationary source that could not reasonabl y pass through a stack, chimney , vent, or other functionally

equivalent opening. Equipment leak emissions at onshore natural gas proce ssing plants are covered under c hapter 8 of this document. 

### 9.2 **Fugitive Emissions Description and Data**  **9.2.1 Fugitive Emissions Description**  There are several potential sources of fugitive emissions throughout the ONG source category . Fugitive emissions occur when connection points are not fitted properly or when seals and gaskets start to deteriorate. Changes in pressure and pressure or mechanical stresses can also cause fugitive emissions from components or equipment . Potential sources of fugitive emissions include valves, connectors, pressure relief devices, open - ended lines (OEL) , access doors, flanges, closed vent sy stems, thief hatches or other openings on storage vessels, agitator seals, distance pieces, crankcase vents, blowdown vents, pump seals or diaphragms, compressors, separators, pressure vessels, dehydrators, heaters, instruments, and meters. Devices that vent as part of normal operations, such as natural gas - driven pneumatic controllers or natural gas - driven***E.O. 12866 Review

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9 - 2 Fugitive Emissions pumps, are not fugitive emissions components, insofar as the natural gas discharged from the device’s vent is not considered a fugitive emission. In April of 2014, the EPA published a white paper titled “Oil and Natural Gas Sector Leaks” 132 that summarized the EPA current understanding of fugitive emissions at onshore ONG production, processing and transmission facilities (referred to herein as the “equipment leaks white paper”). The equipment leaks white paper identified 12 studies or publicly available sources that provided fugitive emission estimates from the various segments of the ONG industry . Many of the fugitive emission measurements were conducted with EPA Method 21 instruments. In addition to EPA Method 21 anal yz ers, several studies cond ucted fugitive emission sur

vey s using OGI in conjunction with portable Method 21 analyzers and gas chromatograph equipment to measure individual VOC compounds. These studies provided emission estimates in the form of component or equipment emission factors or emission estimates by

facility . Fugitive emission estimates for VOC ranged from 0.4 to 10 tpy for ONG production sites. Even though there is a wide variation in the VOC emissions estimates, the studies showed that there are viable options for reducing these emissions. **9.2.2. Emission Data and Emissions Factors**  **9.2.2.1 Summary of Major Studies and Emission Factors**  The equipment leaks white paper provided a summary of fugitive emission studies at ONG production and compressor stations. When we evaluated the emissions and emission reduction options for equipment leaks, many of these studies in the white paper were consulted. Table 9 - 1 presents a list of the studies consulted along with an indication of the ty pe of information contained in the study .

132 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Leaks , Office of Air Quality Planning and Standards. Research Triangle Park, NC. April 2014 . Available at http://www.epa.gov/airquality/oilandgas/2014papers/***E.O. 12866 Review

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9 - 3 Fugitive Emissions

**Tab le 9**  **- 1**  **. Major Studies Reviewed for Emissions and Activity Data Report Name**  **Affiliation Year of**  **Report Activity** 

**Factors Emissions** 

**Data Control** 

**Options** Protocol for Equipment Leak Emission Estimates a EPA 1995 None X X Methane Emissions from the Natural Gas Industry: Equipment Leaks b GRI/EPA 1996 Nationwide X X Greenhouse Gas Reporting Programc EPA 2013 Facility X Inventory of Greenhouse Gas Emissions and Sinks: 1990 - 2011 d EPA 2013 Regional X Measurements of Methane Emissions at Natural Gas Production Sites in the United States e Multiple Affiliations, Academic and Private 2013 Nationwide X X City of Fort Worth Natural Gas Air Quality Study, Final Reportf City of Fort Worth 2011 Fort Worth, TX X X Measurements of Well Pad Emissions in Greeley, CO g ARCADIS/Sage Environmental Consulting/ EPA 2012 Colorado X X Quantifying Cost - Effectiveness of Systematic Leak Detection and Repair Programs Using Infrared 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 Methane 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 Methane 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 X X***E.O. 12866 Review

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9 - 4 Fugitive Emissions a. U.S. Environmental Protection Agency. Protocol for Equipment Leak Emission Estimates . Office of Air Quality Planning and Standards. Research Triangle Park, NC. November 1995. EP A - 453/R - 95 - 017. Available at http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf . b. Gas Research Ins titute (GRI)/U.S. Environmental Protection Agency. Research and Development , Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks . June 1996 (EPA - 600/R - 96 - 080h). c. U.S. Environmental Protection Agency. Petroleum and Natural Gas Systems: 2012 Data Summary . Greenhouse Gas Reporting Program. October 2013. d. U.S. Environmental Protection Agency. Inventory of Greenhouse Gas Emissions and Sinks: 1990 - 2011 . Climate Change Division, Washington, DC. April 2013 . Available at http://www.epa.gov/climatechange/Downloads/ghgemissions/US - GHG Inventory- 2013 - Chapter - 3 - Energy.pdf . e. Allen, David, T., et al. Measurements of methane emissions at natural gas production sites in the United States . Proceedings of the National Academy of Sciences (PNAS) 500 Fifth Street, NW NAS 340 Washington, DC 20001 USA. October 29, 2013. 6 pgs. Available at http://www.pnas.org/content/early/2013/09/10/1304880110.full.pdf+html . f. ERG and Sage Environmental Consulting, LP. City of Fort Worth Natural Gas Air Quality Study, Final Report . Prepared for the City of Fort Worth, Texas. July 13, 2011. Available at http://fortworthtexas.gov/gaswells/default.aspx?id=87074 . g. Modrak, Mark T., et al . Understanding Direct Emissions Measurement Approaches for Upstream Oil and Gas Production Operations. Air and Waste Management Association 105 th Annual Conference and Exhibition , June 19 - 22, 2012 in San Antonio, Texas. h . Carbon Limits. Quantifying cost- effectiveness of systematic Leak Detection and Repair Programs using Infrared cameras . Decem ber 24, 2013. Available at http://www.catf.us/resources/publications/files/CATF Carbon_Limits_Leaks_Interim_Report.pdf . i. Thoma, Eben D., et al. Assessment of Methane and VOC Emissions from Select Upstream Oil and Gas Production Operations Using Remote Measurements, Interim Report on Recent Studies. Proceedings of the 105 th Annual Conference of the Air and Waste Management Association , June 19 - 22, 20 12 in San Antonio, Texas. j. ICF International. Economic Analysis of Methane Emission Reduction Opportunities in the U.S . Onshore Oil and Natural Gas Industries . ICF International (Prepared for the Environmental Defense Fund). March 2014. k. Clearstone Engineering Ltd. Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas Processing Plan ts. 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. **9.2.2.2 Model Plants**  Facilities in the ONG source category consist of a variety of combinations of process equipment and components. This is particularly true in the production segment of the industry , where “surface sites” can vary from sites where only

a wellhead and associated piping is located to sites where a substantial amount of separation, treatment, and compression occurs. In order to conduct anal ys es to be used in evaluating potential options to reduce fugitive emissions from well sites and gathering and boosting station s, a model plant a pproach was used. The following sections discuss the creation of these model plants. We obtained i nformation related to equipment counts for natural gas well sites and gathering and boosting station s from the GRI/EPA natural gas industry study 133 . This document also provided average component counts for equipment in the natural gas production segment. The ty pes of components that are associated with this equipment include: valves, connectors, open - ended lines, and pressure relief valves. These average counts were used to develop an average model plants for well sites in the production segment of the industry and for a gathering 133 Gas Research Institute (GRI)/U.S. Environmental Protection Agency. Research and Development, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. June 1996 (EPA - 600/R- 96 - 080h).***E.O. 12866 Review

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9 - 5 Fugitive Emissions and boosting station . Equipment counts associated with oil well sites were obtained from an API Workbook. These equipment counts are consistent with those contained in the EPA’s anal ys is to estimate methane emissions conducted in support of the GHGRP. These model plants are discussed in the following sections. Well Sites ONG pro duction varies from one site to the next . Some production sites may include onl y a single wellhead that is extracting oil or natural gas from the ground, while other sites may include multiple wellheads attached to a well site. A well site is a site where the production, extraction, recovery , lifting, stabilization, separation and/or treating of petroleum and/or natural gas (including condensate) occurs. These sites include all equipment (including piping and associated components, compressors, generators, separators, storage vessels, and other equipment) associated with these operations. A well site can serve one well on a pad or multiple wells on a pad. Therefore, the number of components with potential for fugitive emissions can vary depending on the number of wells feeding into the production pad and the amount of processing equipment located at the site. We used e quipment count data from the EPA GHG Inventory to calculate the average counts of production equipment located at a well site. The ty pes of production equipment located at a well site include: gas wellheads, separators, meters/piping, heaters, and dehydrators. The ty pes of components that are associated with this equipment include: valves, connectors, open ended lines, and pressure relief valves. Component counts for each of the equipment i tems were calculated using the average component counts for gas production equipment in the Eastern U.S and the Western U.S. for the EPA/GRIdocument. A model plant was developed using the average number of wells associated with a well site using data fro m the Drillinginfo HPDI database . 134 B aseline fugitive emissions from well sites depend upon the quantity of equipment and components, which in turn is based on this estimate of wells per pad. To estimate the average number of wells co - located on the same si te as a new well completion or recompletion, the EPA developed a pair of algorithms that identified new and existing wells within a given distance of a new well completion or recompletion. This distance was assumed to represent the distance that, if other wells were within the distance, the

134 Drilling Information, Inc. 2011. DI Desktop. 2011 Production Information Database.***E.O. 12866 Review

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9 - 6 Fugitive Emissions wells would likely

be co - located with the well under examination on the same site. The algorithms were written in the open source R programming language. 135 The HPDI well and production data used to estimate the average number of well co located on a well site drew upon the latitude and longitude of new well completions and recompletions as well as the coordinates of all wells producing oil or natural gas in 2012. The first algorithm estimated the distances between each n ew completion and recompletion and all producing wells, which also includes wells newly completed and producing in 2012 within the same county as the completed well. If the distance between the completed well and producing well was less than the assumed si ze of a ty pical well site, we assumed the two wells were co located. This algorithm progressed county by county across the U.S. where ONG production occurred in 2012 to identify all co - located wells in the U.S. The number of new well completions and recomp letions in 2012 was about 44,000, which includes ONG wells whether they were hydraulicall y fractured or not. All wells producing in 2012 numbered about 1.27 million. The second algorithm processed the result s of the first such that a well can only appear once on a modelled well site. Once these algorithms were complete and produced a results file we converted the results into a “kml” file that enabled the visual inspection of the results within Google Earth. We did not visually inspect ev ery site in the U.S. linked to a 2012 completion or recompletion as the y numbered greater than 20,000. Instead, we examined sites randomly across a range of ONG production regions. The results of this visual examination indicated the algorithms were functi oning as intended. We estimated the number of wells per site assuming sites of one, two and three acres, based upon input from petroleum industry data analy sts. Table 9 - 2 shows the high - level results of these analy ses. **Table 9 -**  **2 .**  **Estimated Average Number of Wells per Site of New Well Completion in 2012 Assu**  **med Well Site Size No. of**  **Well Sites No. of** 

**Wells at Sites Average of Wells**  **Per Site** One Acre 29,213 50,599 1.73 Two Acres 28,938 52,422 1.81 Three Acres 28,710 53,981 1.88

135 See the website < http://www. r - project.org/> for more information on R.***E.O. 12866 Review

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9 - 7 Fugitive Emissions For assumed well sites of two acres, the anal ys 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 sites include about 8,500 existing wells producing in 2012. However, the high level summary presented in Table 9 - 3 masks variation by basins and well ty pes. Table 9 - 3 p resents more detail along these dimensions for the assumed two - acre well site. **Table 9 -**  **3 .**  **Estimated Average Number of Wells per Two Acre Site of New Well Completion and Recompletion in 2012, by HPDI Basin and Type of Well (Oil or**  **Natural Gas, Hydraulically Fractured or Not)** 

**Oil Well Completions**  **Natural Gas Well**

**Completions HPDI Basin**  **No. Of Sites**  **HF Not** 

**HF All**  **HF Not** 

**HF All**  **Total** Los Angeles 23 N/A 13.07 13.07 N/A N/A N/A 13.07 Piceance 111 2.00 1.00 1.75 6.72 11.75 10.14 9.84 Arctic Ocean 2 N/A 5.50 5.50 N/A N/A N/A 5.50 Green River 164 2.23 1.57 2.01 4.37 1.13 4.19 3.88 Unidentified 226 1.18 3.57 3.38 1.00 1.77 1.44 3.22 San Joaquin Basin 1,745 1.56 3.46 3.21 2.61 1.42 2.24 3.16 Arkoma Basin 374 4.00 1.33 2.00 3.06 1.00 3.01 3.00 Denver Julesburg 826 2.63 3.10 2.75 1.48 3.14 1.72 2.46 Ft Worth Basin 1,305 2.05 1.86 1.91 3.27 1.10 2.93 2.33 Central Western Overthrust 7 1.50 N/A 1.50 2.60 N/A 2.60 2.29 Ventura Basin 1 N/A 2.00 2.00 N/A N/A N/A 2.00 Arctic Slope 42 N/A 2.13 2.13 N/A 1.65 1.65 1.99 Ouachita Folded Belt 181 2.01 1.90 1.99 1.50 1.00 1.43 1.97 Salina Basin 13 N/A 1.92 1.92 N/A N/A N/A 1.92 Palo Duro Basin 81 1.42 1.97 1.89 1.00 N/A 1.00 1.86 Uinta 548 1.16 1.33 1.32 N/A 3.33 3.33 1.83 Texas & Louisiana Gulf Coast 3,994 2.03 1.82 1.96 1.37 1.14 1.28 1.79 Central Kansas Uplift 450 N/A 1.78 1.78 N/A 1.53 1.53 1.77 Permian Basin 8,507 1.66 1.76 1.69 1.50 1.57 1.52 1.68 Sedgwick Basin 240 N/A 1.67 1.67 1.67 1.55 1.55 1.62 Las Animas Arch 25 1.00 1.64 1.61 N/A 1.50 1.50 1.60 Nemaha Anticline 38 N/A 1.55 1.55 N/A N/A N/A 1.55 Arkla Basin 811 1.09 1.57 1.49 1.47 1.09 1.42 1.46***E.O. 12866 Review

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9 - 8 Fugitive Emissions **Oil Well Completions**  **Natural Gas Well**

**Completions HPDI Basin**  **No. Of Sites**  **HF Not** 

**HF All**  **HF Not** 

**HF All**  **Total** Chautauqua Platform 461 1.36 1.57 1.49 1.64 1.03 1.35 1.45 Cook Inlet Basin 9 N/A 2.00 2.00 N/A 1.29 1.29 1.44 Appalachian 2,496 1.14 1.05 1.10 2.28 1.10 1.77 1.43 Williston 1,570 1.36 1.00 1.35 1.43 1.00 1.39 1.35 Cherokee Basin 271 1.17 1.29 1.29 N/A 1.69 1.69 1.35 San Juan 158 1.00 1.00 1.00 1.38 1.20 1.37 1.31 East Texas Basin 618 1.25 1.74 1.52 1.22 1.06 1.21 1.31 Forest City Basin 172 N/A 1.28 1.28 N/A N/A N/A 1.28 Anadarko Basin 2,663 1.17 1.77 1.37 1.09 1.29 1.13 1.27 South Oklahoma Folded Belt 167 1.17 1.36 1.30 1.11 1.11 1.11 1.24 Chadron Arch 49 N/A 1.22 1.22 N/A N/A N/A 1.22 Sacramento Basin 13 N/A N/A N/A N/A 1.15 1.15 1.15 Mississippi & Alabama Gulf Coast 132 1.00 1.18 1.14 1.00 1.00 1.00 1.14 Central Montana Uplift 10 1.13 1.00 1.10 N/A N/A N/A 1.10 Big Horn 30 1.10 1.11 1.11 1.00 N/A 1.00 1.10 Powder River 232 1.15 1.03 1.12 1.05 1.00 1.04 1.10 Sweet Grass Arch 17 1.00 1.08 1.05 1.50 1.00 1.33 1.10 Paradox 13 1.00 1.10 1.09 1.00 N/A 1.00 1.08 Black Warrior Basin 57 1.00 1.00 1.00 1.00 1.75 1.07 1.05 Wind River 63 1.00 1.02 1.02 1.00 1.00 1.00 1.02 Wasatch Uplift 1 N/A 1.00 1.00 N/A N/A N/A 1.00 North Park 2 1.00 1.00 1.00 N/A N/A N/A 1.00 Raton 20 N/A N/A N/A 1.00 1.00 1.00 1.00 **Grand Total 28,938**  **1.64 1.99**  **1.79 1.90**  **1.76 1.86**  **1.81** Table 9 - 3 provides data that the concentration of wells at production sites varies greatly by basin. However, the analy sis indicates that most wells sites have relatively few or no co located wells, which brings the national average wells per new completion or recompletion site t o 1.81 for the two - acre well site. While the analysis shows variation by basin, at the national level, there is relativel y little variation across ONG well completion sites and whether the new wells were completed or recompleted using hydraulic fracturing. For example, oil well sites averaged 1.79 wells per site while natural gas wells averaged 1.86. As a result of this anal ys i s, based upon professional judgment, 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***E.O. 12866 Review

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9 - 9 Fugitive Emissions at sites of new completions and recompletions. Also, to simplify anal ys is of costs and emissions at well sites, we rounded the 1.81 national average wells per site to 2. While we are confident that the assumed two acre well site is a reasonable size to capture most co - located wells in 2012, it is by no means a perfect assumption. First, industry and state regulatory

trends indicate that well drilling will likely become increasingl y concentrated on sites, potentially

leading to an increase in the average number of wells per well site. However, it is not possible at this point to forecast this increasing concentration, especiall y with the variations by fields described above. Also, it is possible that two acres is too small to accuratel y 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. A lternatively , the assumed two acres might over - estimate the size of sites in some fields and, as a result, pull in more than one site, overestimating the number of wells on the site. We also noted that the latitude and longitude values on many wells were l ikel y incorrect or exact duplicates of other wells. Despite these caveats, we believe that the well site anal ys is described here produces a reasonable estimate of national average of number of wells on new well completion and recompletion sites in 2012. Th erefore, based on this anal ys is, the model plant for an ONG production site was based on a well site with 2 wells. For natural gas well sites, the model plant was developed using the average equipment and fugitive emissions components counts for gas produ ction data from the GRI/EPA report. The average equipment count for a gas well was estimated b y weighting the average of equipment counts for the Eastern and Western U.S. data sets for gas production equipment. The weighted averages of the data sets were d etermined to be 1.6 separators, 0.8 meters/piping, 0.8 in - line heaters, and 0.6 dehydrators per well. The total natural gas well site equipment counts were calculated b y multiplying the average well equipment values by the average number of wells per well site (2), and rounding the product to the nearest integer. Average component counts for each of the equipment items were calculated using the average component counts for onshore production equipment in the Eastern U.S and the Western U.S. from the EPA/GRI study . The total number of fugitive emissions components was calculated b y multiplying the rounded equipment counts by

the component count per equipment and rounding to the nearest integer. Table 9 - 4 presents a summary of the fugitive emissions component counts for natural gas well sites.***E.O. 12866 Review

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9 - 10 Fugitive Emissions For oil well sites, the model plant was developed using equipment counts from an API workbook and component count data from the GRI/EPA study . The average equipment count for an oil well were determined to be 0.7 separato rs, 0.7 headers, and 0.03 heater/treaters per well. The total oil well site equipment counts were calculated b y multiplying the average well equipment values by the average number of oil wells per oil well site (2), and rounding the product to the nearest integer. Average component counts obtained from the APIworkbook were used to calculate the total number of components by multiplying the rounded equipment counts by the component count per equipment and rounding up to the nearest integer. Table 9 - 5 presents a summary of the fugitive emissions component counts for oil well sites. Baseline model plant emissions for the natural gas and oil well sites were calculated using the fugitive emissions component counts and the component ONG production emission factor s from AP - 42 136 . Annual emissions were calculated assuming 8,760 hours of operation each ye ar. The emissions factors are provided for total organic compounds (TOC) and include non VOC. Table 9 - 6 presents the emission factors used to estimate the emissions from the production segment (e.g., oil well sites, natural gas well sites, gathering and boosting stations). Emissions of VOC were calculated using weight ratios for VOC/TOC as described in the 2011 Gas Composition Memorandum 137 . Tables 9 - 7 and 9 - 8 present summaries of the fugitive emissions component counts, average methane emissions factors and VOC emissions for natural gas and oil well sites, respectivel y. The average fugitive emissions from a gas well model plant were determined to be 1.26 tpy of VOC and th e average fugitive emissions from an oil well model plant were determined to be 1.09 tpy of methane and 0.30 tpy

of VOC. These emissions were used to estimate the potential emission reductions and cost of control of a fugiti ve emissions reduction program. Baseline emissions for the natural gas well site model plant were calculated using the equipment and fugitive emissions component counts and the representative gas service emission factors. Emissions were estimated using the EPA Protocol which provided TOC emission factors

136 U.S . EPA, Protocol for Equipment Leak Emission Estimates, Table 2 - 4, November 1995. (EPA - 453/R- 95 - 017) 137 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.***E.O. 12866 Review

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9 - 11 Fugitive Emissions **Table 9 -**  **4 .**  **Average Component Count for Natural Gas Well Site Model Plant Equipment**  **Model Plant**

**Equipment Counts**  **Average Component Count per Equipment**  **a Average Component Count per Model Plant** 

**Valves Connectors**  **OELs PRVs**  **Valves Connectors**  **OELs PRVs**  Gas Wellheads 2 9 37 1 0 19 74 1 0 Separators 2 22 68 4 1 43 137 7 2 Meters/Piping 1 13 48 0 0 13 48 0 0 In - Line Heaters 1 14 65 2 1 14 65 2 1 Dehydrators 1 24 90 2 2 24 90 2 2 Total 113 414 12 5 Rounded up Total 114 414 14 6 a Data Source: EPA/GRI, CH 4 Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks , Table 4 - 4 and 4 - 7, June 1996. (EPA - 600/R - 96 - 080h)***E.O. 12866 Review

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9 - 12 Fugitive Emissions **Table 9 -**  **5 .**  **Average Component Count for Oil Well Site Model Plant Equipment**  **Model Plant**

**Equipment Counts**  **Average Component Count per Equipment a**  **Average Component Count per Model Plant**

**Valves Connectors**  **OELs PRVs**  **Valves Connectors**  **OELs PRVs**  Oil Wellheads 2 5 18 0 0 10 36 0 0 Separators 1 6 22 0 0 6 22 0 0 Headers 1 5 14 0 0 5 14 0 0 Heater/Treaters 1 8 32 0 0 8 32 0 0 Total 29 104 0 0 Rounded up Total 29 104 1 1 a Data Source: EPA/GRI, CH 4 Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4 - 4 and 4 - 7, June 1996. (EPA - 600/R - 96 - 080h)***E.O. 12866 Review

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9 - 13 Fugitive Emissions **Table 9 -**  **6 .**  **ONG Production Operations Average TOC Emissions Factors**  **Component Type Component** 

**Service TOC 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 9 -**  **7 .**  **Estimated Fugitive VOC Emissions for Natural Gas Production Model Plant Natural Gas Well**  **Site Model Plant Component**  **Model Plant**

**Component Count**  **a Uncontrolled** 

**TOC Emission Factor**  **b (kg/hr/comp)**  **Uncontrolled VOC Emissions**  **(tpy) c**  Valves 114 0.0045 0.957 Connectors 414 0.0002 0.154 OELs 14 0.002 0.052 PRVs 6 0.0088 0.098 Total 1.26 a Component count values for model plant are based on a 2 wellhead pad and are rounded to the nearest integer. b TOC emission factors obtained from Table 2 - 4 for the EPA Equipment Leaks Protocol for components in gas service. c VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from the 2011 Gas Composition Memorandum. **Table 9 -**  **8 .**  **Estimated Fugitive VOC Emissions for Oil Well Site Model Plant Natural Gas Well**  **Site Model Plant Component**  **Model Plant**

**Component Count**  **a Uncontrolled** 

**TOC Emission Factor**  **b (kg/hr/comp)**  **Uncontrolled VOC Emissions**  **(tpy) c**  Valves 29 0.0045 0.243 Connectors 104 0.0002 0.039 OELs 1 0.002 0.004 PRVs 1 0.0088 0.016 Total 0.302 a Component count values for model plant are based on a 2 wellhead pad and are rounded to the nearest integer. b TOC emission factors obtained from Table 2 - 4 for the EPA Equipment Leaks Protocol for components in gas service. c VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from the 2011 Gas Composition Memorandum.***E.O. 12866 Review

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9 - 14 Fugitive Emissions for production sources (w ell sites, gathering and boosting). The VOC emissions were calculated using weight fractions provided in the 2011 Gas Composition Memorandum. Annual emissions were calculated assuming 8,760 hours of operation each ye ar. Table 9 - 6 presents the emission factors for the natural gas and oil production segments . Emissions of VOC were calculated using weight ratios for VOC as described in the gas composition memorandum developed for the 2012 NSPS 138

. A summary of the equipment counts, and average TOC emissions factors and VOC emissions for natural gas and oil well sites are provided in Tables 9 - 7 and 9 - 8, respectivel y . Using these data , the average fugitive emissions from a gas well model plant was determined to be 1.3 tpy of VOC and the average fugitive emissio ns from an oil well model plant was determined to be 0.30 tpy of VOC. The VOC emission estimates were used to evaluate the potential emission reductions and cost of control of a f ugitive emissions reduction program. Gathering and Boosting S tation s Gathering and boosting station s are sites that collect natural gas from well sites and direct them to the natural gas processing plants. These stations have similar equipment to well sites; however they

are not directly

connected to the wellheads. The gath ering and boosting station model plant was developed using the average equipment and fugitive emissions component counts for onshore production from the GRI/EPA study . The average equipment counts for a gathering and boosting station were estimated b y weighting the average of equipment counts for the Eastern and Western U.S. data sets for onshore production equipment. The weighted averages of the data sets were determined to be 11 separators, 7 meters/piping, 5 gathering compressors, 7 in - line heaters, and 5 dehydrators. Fugitive emissions component counts for each of the equipment items were calculated using the average component counts for onshore production equipment in the Eastern U.S and the Western U.S. from the EPA/GRIstudy . The components for gathering compressors were included in the model plant total counts, but the compressor seals were excluded. Comp ressors seals are addressed in c hapter 8 of this document. Table 9 - 9 presents a summary of the fugitive emissions component counts for gathering and boosting station s.

138 Memorandum to Bruce Moore from Heather Brown. Composition of Natural Gas for Use in the Oil and Natural Gas Sector Rulemaking . EC/R, Incorporated. June 29, 2011.***E.O. 12866 Review

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9 - 15 Fugitive Emissions Baseline emissions were calculated using the component counts and the TOC emission factors for ONG production (See Table 9 - 6). Table 9 - 10 summarizes the baseline emissions for gathering and boosting stations. The average fugitive emissi ons from a gathering and boosting station were determined to be 9.8 tpy of VOC. The VOC emission estimate was used to evaluate the potential emission reductions and cost of control of a fugitive emissions reduction program.***E.O. 12866 Review

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9 - 16 Fugitive Emissions **Table 9 -**  **9 .**  **Average Component Count for the ONG**  **Production Gathering and Boosting S**  **tation Model Plant**  **Equipment Model** 

**Plant Equipment**  **Counts Average Component Count per Equipment**  **a Average Component Count per Model Plant** 

**Valves Connectors**  **Open**   ** Ended** **Lines Pressure** 

**Relief Valves Valves**  **Connectors Open**  **- Ended**  **Lines Pressure** 

**Relief Valves**  Separators 11 22 68 4 1 242 748 44 11 Meters/Piping 7 13 48 0 0 91 336 0 0 Gathering Com pressors 5 71 175 3 4 355 875 15 20 In - Line Heaters 7 14 65 2 1 98 455 14 7 Dehydrators 5 24 90 2 2 120 450 10 10 Total 906 2,864 83 48 a Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4 - 4 and 4 - 7, June 1996. (EPA - 600/R - 96 - 080h)***E.O. 12866 Review

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9 - 17 Fugitive Emissions **Table 9 -**  **10 .**  **Estimated Fugitive Methane and VOC Emissions for the ONG**  **Production**

**Gathering and Boosting S**  **tation Model Plant**  **Component Model Plant** 

**Component Count**  **a Component TOC** 

**Emission Factor (kg/hr/ component)**  **b VOC**  **Emissions (tons/yr)**  **c** Valve 906 0.0045 7.6 Connectors 2,864 0.0002 1.1 OEL 83 0.002 0.3 PRV 48 0.0088 0.8 Total 9.8 a Component counts from Table 9 - 7. Component count values for model p lant are based on 2 wellhead site s 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 servic e. c VOC emissions calculated using 0.193 weight ratio for VOC/TOC obtained from gas composition memorandum. 

### 9.3 **Available Controls and Regulatory A**  **pproaches 9.3.1**  **Available VOC Emission Control Options** The EPA has determined that fugitive emissions from components are a significant source of VOC emissions from well sites and gathering and boosting station s. Based on the review of public and peer review comments on the equipment leaks white paper and the Colorado and Wyoming state rules, the EPA has identi fied two options for reducing fugitive VOC emissions from components: a fugitive emissions monitoring program based on the use of OGI leak detection combined with leak correction, and a leak monitoring program based on individual component monitoring using Method 21 for leak detection combined with leak correction. These options, as currently being used by

industry to reduce fugitive emissions in the ONG source category , are described below. **9.3.1.1 Fugitive Leak Detection and Correction with Optical Gas Imaging**  Description The reduction of fugitive emissions from well sites and gathering and boosting station s involves the development of a fugitive emissions monitoring plan. An example plan would incorporate semiannual surveying of equipment and components using OGI. The company m ay use the same monitoring plan for all affected sources, a different plan for each category of a source, or a plan for each individual source. The monitoring plan must include inspection of fugitive emission components ( including but not limited to valves, connectors, pressure relief***E.O. 12866 Review

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9 - 18 Fugitive Emissions devices, open - ended lines, access doors, flanges, closed vent s ys tems, thief hatches or other openings on a storage vessels, agitator seals, distance pieces, crankcase vents, blowdown vents, pump seals or diaphragms, compressors, separators, pressure vessels, deh ydrators, heaters, instruments, and meters) and provisions to repair or replace components or equipment if evidence of fugitive emissions is discovered during the OGI survey . All repairs must be made as soon as practicable, but no later than 15 calendar day s after the OGI survey . In addition, all repairs must be re - surveyed immediately after repair using OGI to ensure the fugitive emissions are no longer visible. Control Effectiveness P otential e mission reduction percentage s from the implementation of an OGI monitoring program varies from 40 to 99 percent. 139 The data from these studies are based on the gathering of individual OGI surveys at various ONG segment sites. The variation in the percent re ductions from these OGI survey s generall y depended on whether large fugitive emission sources were found (e.g., open thief hatches, open dump valves, etc.) during the OGI survey and other assumptions made by

the authors. However, these studies in the white paper did not provide information on the potential emission reductions from the implementation of an annual, semiannual, quarterly

or monthly

OGI monitoring and repair program. A report was found after the publication of the white paper from the Colorado Air Quality Control Commission 140 estimated (1) 40 percent reduction for annual OGI monitoring for well production tank batteries with an uncontrolled VOC emissions of greater than 6 tpy or less than or equal to 12 tpy ; (2) 60 percent reduction for quarterl y OGI monitoring for well production tank batteries with an uncontrolled VOC emissions of greater than 12 tpy and less than or equal to 50 tpy ; (3) 60 percent reduction for quarterl y OGI monitoring for well production tank batteries with uncontrolled VOC emissions of greater than 12 tpy and less than or equal to 50 tpy ; and (4) 80 percent reduction for monthly OGI monitoring at well production tank batteries with uncontrolled VOC emissions greater than 50 tpy . From the review of the studies in the white p aper and the Colorado Economic Impact Analy sis, we expect the emission reductions from the implementation of an OGI monitoring and 139 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Leaks , Office of Air Quality Planning and Standards. Research Triangle Park, NC. April 2014 . Available at http://www.epa.gov/airquality/oiland gas/2014papers 140 Colorado Air Quality Control Commission, Initial Economic Impact Analysis for Proposed Revisions to Regulation Num ber 7 (5 CCR 1001 - 9). November 15, 2013.***E.O. 12866 Review

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9 - 19 Fugitive Emissions repair program to vary

depending on the frequency of monitoring. For this analy sis, we estimated emissions reductions for the OGI monitoring frequency options (annual, semiannual and quarterl y) using the estimated emission reductions from Colorado’s Economic Impact Anal ys is for conducting the OGI monitoring and repair program . Based on this range of expected emission reductions as characterized b y Colorado’s Economic Impact Analy sis , it is expected that an OGI monitoring program in combination with a repai r program can reduce fugitive methane and VOC emissions from these segments by 40 percent on an annual frequency , 60 percent o n a semiannual frequency and 80 percent on a quarterly frequency as well as minimize the loss of salable gas. Table s 9 - 9, 9 - 10 and 9 - 11 summarize th e estimated emission reductions for annual, semiannual and quarterl y OGImonitoring for the ONG well site mo del plants and the gathering and boosting station model plant . Cost Impacts Costs (2012 dollars) for preparing and implementing a fugitive emission monitoring plan were estimated using hourly estimates for each of the plan elements. The costs are based on the following assumptions: 1) Labor cost for each of the monitoring plan elements was estimated to be $57.80 per hour; 2) Reading of the rule and instructions would take one person four hours to complete at a cost of $231.20 ; 3) Development of a fugitive emission monitoring plan would take two and one half people a total of 60 hours to complete at a cost of $3,468; 4) Initial activities planning are estimated to take two people a total of 16 hours to complete at a cost of $1,849; 5) For companies that own and operate well sites, the cost of notification of compliance status was estimated to be $58 for 22 well sites for a total of $1,272 per company . For gathering and boosting station s the total notificati on cost was estimated to be $5 8; and 6) Subsequent activities planning are estimated to take two people a total of 12 hours to complete at a cost of $1,387. For well sites, this cost was divided among the total number of well sites owned by a company , which was assumed to be 22. The cost per well site was estimated to be $63.***E.O. 12866 Review

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9 - 20 Fugitive Emissions Costs for implementing a fugitive emission monitoring plan on a company level for well sites and a facility

level for gathering and boosting station s were estimated for each of the monitoring and repair elements. The costs are based on the following assumptions: Costs for implementing a fugitive emission monitoring plan on a company level for well sites and a facility

level for gathering and boosting stations were estimated for each of the monitoring and repair element s. The costs are based on the following assumptions: 1) The cost for OGI monitoring using an outside contractor was assumed to be $600 for a well site and $2,300 for a gathering and boosting station for each survey ; 2) Repair costs were estimated to be $299 for well sites and $3,436 for gathering and boosting stations per survey . These costs were estimated assuming that 1.18 percent of the components leak and 75 percent are repaired online and 25 percent are repaired offline; 3) Cost for resurvey

of components after offline repair based on $2.00 per component resurveyed. This is based on the assumption that a company purchases Method 21 instrumentation (estimated to be $10,800 141 ) and is able to perform the resur vey without needing contractors; and 4) Preparation of annual reports was estimated to take one person a total of 4 hours to complete at a cost of $231. The initial setup cost or capital cost s for well sites was calculated b y summing up the costs for reading the rule, development of fugitive emissions monitoring pl an, initial activities planning, and notification of initial compliance status. The total capital cost s of these activities was calculated to be $17,620 per company. Assuming that each company owns and operates 22 well sites, the capital cost s per well sit e was estimated to be $801. For gathering and boosting stations, the capital costs was estimated to be $16,407 per facility . For well sites and gathering and boosting stations, the annual cost s include : subsequent activities planning, OGI camera survey by an outside contractor, cost of repair of fugitive emissions found, preparation and submittal of an annual report, storing and filing of records, and the amortized capital cost s over eight years at seven percent discount rate. The annual costs for annual, semiannual and quarterl y camera surveying (inclusive of contractor costs, cost of repair

141 Memorandum to Jodi Howard, EPA/OAQPS from Cindy Hancy, RTI International, Analysis of Emission Reduction Techniques for Equipment Leaks, December 21, 2011. EPA - HQ - OAR - 2002 - 0037 - 0180***E.O. 12866 Review

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9 - 21 Fugitive Emissions of fugitive emissions found, preparation and submittal of an annual report, a nd amortized capital cost s over eight years at seven percent interest) were calculated for each of the source category segments. Table 9 - 11, 9 - 12 and 9 - 13 present summaries of the cost of control for VOC for the three OGI monitoring frequency options (i.e., annu al, semiannual and quarterly). **Table 9 -**  **11 .**  **Summary of the Model Plant VOC Cost of Control for the Annual OGI Monitoring Option** 

**Model Plant Annual**  **VOC Emission**  **Reductions (tpy)**  **a Capital** 

**Cost s**  **($2012) b**  **Annual Cost s** 

**($2012/year) c**  **Cost of Control ($2012/ton)**  **Without savings**  **With**

**savings d**  **Without**

**savings With** 

**savings d**  Natural Gas Well Site 0.50 $801 $1,329 $908 $2,633 $1,799 Oil Well Site 0.12 $801 $1,329 $1,228 $10,992 $10,158 **Well Site Program Weighted**  **Average e**  **$8,903 $8,069**  Gathering and Boosting Station 3.9 $16,407 $10,124 $6,865 $2,591 $1,757

a. Assumes 40% reduction with the implementation of annual OGI camera monitoring. b. The capital cost s for ONG well sites and gathering and boosting stations includes the cost of implementing the monitoring program which includes reading the rule, developing and implementing a monitoring plan (including initial activities planning), notification of initial compliance status, and purchase of a Method 21 monitoring device. c . Annual cost s for ONG well sites and gatheri ng and boosting stations include annual monit oring and repair costs and amortization of the capital cost s over 8 years at 7% interest. d . Recovery credit s were calculated based on methane reductions , assuming methane i s 82.9% of natural gas composition, an d the value of the natural gas recovered as $4 Mcf. e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well site s and 16,562 oil well site s.***E.O. 12866 Review

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9 - 22 Fugitive Emissions **Table 9 -**  **12 .**  **Summary of the Model Plant VOC Cost of Control for the Semiannual OGI**  **Monitoring Option**

**Model Plant Annual VOC**  **Emission Reductions**  **(tpy) a**  **Capital**

**Cost s**  **($2012) b**  **Annual Cost s** 

**($2012/year) c**  **Cost of Control ($2012/ton)**  **Without savings**  **With**

**savings d**  **Without**

**savings With** 

**savings d**  Natural Gas Well Site 0.76 $801 $2,230 $1,599 $2,945 $2,111 Oil Well Site 0.18 $801 $2,230 $2,079 $12,294 $11,460 **Well Site Program Weighted Average**  **e $9,958**  **$9,124** Gathering and Boosting Station 5.9 $16,407 $15,881 $10,993 $2,710 $1,876

a. Assumes 6 0% reduction with the implementation of annual OGI c amera monitoring. b . The capital cost for ONG well sites and gathering and boosting stations includes the cost of imple menting the monitoring program which includes reading the rule, developing and implementing a monitoring plan (including initial activities planning), notification of initial compliance status, and purchase of a Method 21 monitoring device. c . Annual cost s for ONG well sites and gathering and boosting stations include semi annu al monit oring and repair costs and amortization of the capital cost over 8 years at 7% interest. d . Recovery credits were calculated based on methane reductions , assuming that methane is 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well site s and 16,562 oil well site s.***E.O. 12866 Review

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9 - 23 Fugitive Emissions **Table 9 -**  **13 .**  **Summary of the Model Plant VOC Cost of Control for the Quarterly OGI**  **Monitoring Option**

**Model Plant Annual VOC**  **Emission Reductions**  **(tpy) a**  **Capital**

**Cost s**  **($2012) b**  **Annual Cost s** 

**($2012/year) c**  **Cost of Control ($2012/ton)**  **Without savings**  **With**

**savings d**  **Without**

**savings With** 

**savings d**  Nat ural Gas Well Site 1.01 $801 $4,031 $3,190 $3,994 $3,160 Oil Well Site 0.24 $801 $4,031 $3,830 $16,669 $15,836 **Well Site Program Weighted Average**  **e $13,502**  **$12,668** Gathering and Boosting Station 7.81 $16,407 $27,396 $20,879 $3,506 $2,672

a Assumes 80% reduction with the implementation of quarterly OGI camera monitoring. b The capital cost s for ONG well sites and gathering and boosting stations includes the cost of implementing the monitoring program which includes reading the rule, developing and implementing a monitoring plan (including initial activities planning), notification of initial compliance status, and purchase of a Method 21 monitoring device. c . Annual cost s for ONG well sites and gathering and boosting stations include quarterly monit oring and repair costs and amortization of the capital cost s over 8 years at 7% interest. d Recovery credits were calculated assuming natural gas reductions based methane reductions, methane as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well site s and 16,562 oil well site s. **9.3.1.2 Fugitive Leak Detection and Correction with Method 21** Description Another option that can be used to reduce fugitive emissions from well sites and gathering and boosting stations involves the development of a fugitive emissions monitoring plan using Method 21 to detect leaks from equipment and components. The plan would incorporate surveying of equipment and components at a specified interval and leak definition using a Method 21 instrument. The plan would also include provisions for repair or replacement of equipment or components if evidence of fugitive emissions are di scovered during the survey . The company may use the same monitoring plan for all affected sources, a different plan for each category of a source, or a plan for each individual source. The monitoring plan would include inspection of all fugitive emission c omponents and would require the repair where evidence of fugitive emissions is discovered (as soon as practicable, but generall y no later than 15 calendar day s after the Method 21 survey). In addition, all repairs would be re - surveyed immediately after rep air to ensure the fugitive emissions are below the specified leak definition.***E.O. 12866 Review

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9 - 24 Fugitive Emissions Control Effectiveness Potential control efficiencies for Method 21 monitoring were estimated to be 67 to 98 percent depending on leak definition and monitoring frequency in the 2 015 NSPS proposal. The Method 21 control options included leak definitions of 10,000, 2,500 and 500 parts per million (ppm) and annual, semiannual and quarterl y monitoring frequencies. Tables 9 - 12, 9 - 13 and 9 - 14 present the summaries of the estimated emiss ion reductions for annual, semiannual and quarterl y Method 21 monitoring for the three leak definitions for the well site and the gathering and boosting station model plant s . Cost Impacts Costs (2012 dollars) for preparing and implementing a fugitive emission monitoring plan were estimated using hourly estimates for each of the plan elements. The costs are based on the following assumptions: 1) Labor cost for each of the monitoring plan elements was estimated to b e $57.80 per hour; 2) Reading of the rule and instructions would take one person four hours to complete at a cost of $231.20 ; 3) Development of a fugitive emissio n monitoring plan would take two and one half people a total of 60 hours to complete at a cost o f $3 ,468; 4) Initial activities planning are estimated to take two people a total of 16 hours to complete at a cost of $1,849; 5) For companies that own and operate well sites, the cost notification of compliance status was estimated to be $58 for 22 well sites for a total of $1,272 per company . For gathering and boosting stations the notification of complian ce cost was estimated to be $58; 6) The cost of purchasing a Method 21 monitoring device and data collection sy stem was esti mated to be $25,300 per company; and 7) Sub sequent activities planning are estimated to take two people a total of 12 hours to complete at a cost of $1,387. Fo r ONG well sites, this cost was divided among the total number of well sites owned by a company , which was assumed to be 22. The cost per we ll site was estimated to be $63. For gathering and boosting stations the subsequent activities planning was estimated to be $1,387.***E.O. 12866 Review

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9 - 25 Fugitive Emissions Costs for implementing a fugitive emission monitoring plan on a company level for well sites and a facility

level for gathering and boosting stations were estimated for each of the monitoring and repair elements. The costs are based on the following assumptions: 1) Method 21 monitoring was estimated to take 2 people a total of 4 hours to survey a well production site at a cost of $462 per survey . For gathering and boosting stations, Method 21 monitoring was estimated to take 2 people a total of 8 hours to survey the stati on at a cost of $925 per survey ; 2) Annual repair costs for well sites were estimated to be $2,999 using a leak definition of 10,000 ppm, $5,067 using a leak definition of 2,500 ppm and $5,400 using a leak definition of 500 ppm . These costs were estimated assuming that 7.49 % of the components leak at 10,000 ppm, 12.25% of the components leak at 2,500 ppm and 13.53% of the components leak at 500 ppm. The repair costs assume 75% are repaired onli ne and 25% are repaired offline; 3) Annual repair costs for gathering and boosting stations were estimated to be $29,288 using a leak definition of 10,000 ppm, $47,821 using a leak definition of 2,500 ppm and $52,900 using a leak definition of 500 ppm . These costs were estimated assuming that 7.49 % of the components leak at 10,000 ppm, 12.25% of the components leak at 2,500 ppm and 13.53% of the components leak at 500 ppm. The repair costs assume 75% are repaired onli ne and 25% are repaired offline; 4) Cost for resurvey

of components after repair based on $ 2.00 per component resurveyed; and 5) Preparation of annual reports was estimated to take 1 person a total of 4 hours to complete at a cost of $231. The initial setup cost or capital cost s for ONG well sites was calculated b y summing up the costs for reading the rule, development of fugitive emissions monitoring plan, initial activities planning, acquisition of a Method 21 monitoring device and data collection sy stem and notification of initial compliance status. The total capital cost s of these activities was estimated to be $ 32 , 12 0 per company . Assuming that each company owns and operates 22 well sites, the capital cost s per well site was estimated to be $ 1,460 . For gathering and boosting stations, the capital cost s includes; reading the rule, development of fugitive emissions monitoring plan, initial activities planning, acquisition of a***E.O. 12866 Review

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9 - 26 Fugitive Emissions Method 21 monitoring device and data collection sy stem and notification of initial compliance status. The total capital cost s of these activities was estimated to be $ 30 , 907 per station . For ONG well sites, the annual cost s include ; subsequent activities plannin g, Method 21 survey , cost of repair of fugitive emissions found, preparation and submittal of an annual report , storing and filing of records , and the amortized capital cost s over eight years at seven percent interest. The annual cost s for annual, semiannual and quarterl y Method 21 surveying (inclusive of cost of repair of fugitive emissions found, preparation and submittal of an annual report, and amortized capital cost s over eight years at seven percent interest) were calculated for each of the so urce category

segments. Tables 9 - 14, 9 - 15 and 9 - 16 present summaries of the cost of control for VOC at each of the leak definitions (i.e., 10,000, 2,500, and 500 ppm) for the three monitoring frequency

options (i.e., annual, semiannual and quarterl y).***E.O. 12866 Review

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9 - 27 Fugitive Emissions **T able 9**  **- 14**  **. Summary of the Model Plant VOC Cost of Control for the Annual**  **Method 21 Monitoring Option** 

**Model Plant Annual**  **VOC Emission**  **Reductions (tpy)**  **a Capital** 

**Cost s**  **($2012) b**  **Annual Cost s** 

**($2012/year) c**  **Cost of Control ($2012/ton)**  **Without savings**  **With**

**savings d**  **Without**

**savings With** 

**savings d**  **10,000 ppm Leak Definition** Natural Gas Well Site 1.03 $1,460 $4,02 0 $3,15 7 $3,885 $3,051 Oil Well Site 0.20 $1,460 $4,02 0 $3,813 $19,847 $18,826 **Well Site Program Weighted**  **Average e**  **$15,858 $14,884**  Gathering and Boosting Station 8.01 $30,907 $37,203 $30,523 $4,644 $3,810 **2,500 ppm Leak Definition** Natural Gas Well Site 1.19 $1,460 $6,103 $5,113 $5,145 $4,311 Oil Well Site 0.28 $1,460 $6,103 $5,866 $21,475 $20,642 **Well Site Program Weighted**  **Average e**  **$17,394 $16,560**  Gathering and Boosting Station 9.18 $30,907 $55,860 $48,203 $6,083 $5,249 **500 ppm Leak Definition** Natural Gas Well Site 1.24 $1,460 $6,437 $5,406 $5,206 $4,372 Oil Well Site 0.30 $1,460 $6,437 $6,190 $21,728 $20,894 **Well Site Program Weighted**  **Average e**  **$ 17,599**  **$16,765** Gathering and Boosting Station 9.57 $30,907 $60,973 $52,990 $6,369 $5,535

a. Assumes 84% reduction at 10,000 ppm leak definition, 94% reduction at 2,500 ppm leak definition and 98% reduction at 500 ppm leak reduction with the implementation of annual Method 21 monitoring. b. The capital cost s for ONG well sites and gathering and boosting stations includes the cost of implementing the monitoring program which includes reading the rule, developing and implementing a monitoring plan (including initial activities planning), notification of initial compliance status, and purchase of a Method 21 monitoring device. c . Annual cost s for ONG well sites and gathering and boosting stations include annual monit oring and repair costs and amortization of the capital cost s over 8 years at 7% interest. d. Recovery credits for ONG w ell sites were calculated assuming natural gas reductions based methane reductions, methane as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well site s and 16,562 oil well site s.***E.O. 12866 Review

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9 - 28 Fugitive Emissions **Table 9 -**  **15 .**  **Summary of the Model Plant VOC Cost of Control for the Semia**  **nnual Method**  **21 Monitoring Option** 

**Model Plant Annual**  **VOC Emission**  **Reductions (tpy)**  **a Capital** 

**Cost s**  **($2012) b**  **Annual Cost s** 

**($2012/year) c**  **Cost of Control ($2012/ton)**  **Without savings**  **With**

**savings d**  **Without**

**savings With** 

**savings d**  **10,000 ppm Leak Definition** Natural Gas Well Site 0.91 $1,460 $4,482 $3,725 $4,934 $4,100 Oil Well Site 0.22 $1,460 $4,48 2 $4,301 $20,593 $19,759 **Well Site Program Weighted**  **Average e**  **$16,680 $15,846**  Gathering and Boosting Station 7.03 $30,907 $38,128 $32,263 $5,421 $4,587 **2,500 ppm Leak Definition** Natural Gas Well Site 1.16 $1,460 $6,565 $5,597 $5,655 $4,821 Oil Well Site 0.28 $1,460 $6,565 $6,333 $23,605 $22,771 **Well Site Program Weighted**  **Average e**  **$19,119 $18,285**  Gathering amd Boosting Station 8.99 $30,907 $56,785 $49,291 $6,318 $5,485 **500 ppm Leak Definition** Natural Gas Well Site 1.22 $1,460 $6,899 $5,879 $5,637 $4,803 Oil Well Site 0.29 $1,460 $6,899 $6,655 $23,529 $22,695 **Well Site Program Weighted**  **Average e**  **$19,058 $18,224**  Gathering and Boosting Station 9.48 $30,907 $61,898 $53,996 $6,532 $5,698

a. Assumes 72% reduction at 10,000 ppm leak definition, 92% reduction at 2,500 ppm leak definition and 97% reduction at 500 ppm leak reduction with the implementation of annual Method 21 monitoring. b. The capital cost s for ONG well sites and gathering and boosting s tations includes the cost of implementing the monitoring program which includes reading the rule, developing and implementing a monitoring plan (including initial activities planning), notification of initial compliance status, and purchase of a Method 21 monitoring device. c . Annual cost s for ONG well sites and gathering and boosting stations include semiannual monit oring and repair costs and amortization of the capital cost s over 8 years at 7% interest. d . Recovery credits for ONG well sites were calculated assuming natural gas reductions based methane reductions, methane as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. e. The weighted average for well sites was calculated using the 2020 a ctivity counts of 5,518 gas well site s and 16,562 oil well site s.***E.O. 12866 Review

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9 - 29 Fugitive Emissions **Table 9 -**  **16 .**  **Summary of the Model Plant VOC Cost of Control for the Quarterly**  **Method 21**  **Monitoring Option**

**Model Plant Annual**  **VOC Emission**  **Reductions (tpy)**  **a Capital** 

**Cost s**  **($2012) b**  **Annual Cost s** 

**($2012/year) c**  **Cost of Control ($2012/ton)**  **Without savings**  **With**

**savings d**  **Without**

**savings With** 

**savings d**  **10,000 ppm Leak Definition** Natural Gas Well Site 0.85 $1,460 $5, 407 $ 4,702 $ 6,396 $ 5,562 Oil Well Site 0.20 $1,460 $ 5,407 $5, 238 $26, 696 $25, 862 **Well Site Program Weighted Average**  **e $21,623**  **$20,789** Gathering and Boosting Station 6.55 $30,907 $39, 978 $34, 519 $6, 108 $5, 274 **2,500 ppm Leak Definition** Natural Gas Well Site 1.12 $1,460 $7, 490 $ 6,553 $6, 669 $5, 835 Oil Well Site 0.27 $1,460 $7, 490 $7, 265 $27, 838 $ 27,004 **Well Site Program Weighted Average**  **e $22,548**  **$21,714** Gathering and Boosting Station 8.69 $30,907 $58, 635 $51, 385 $6, 744 $5, 910 **500 ppm Leak Definition** Natural Gas Well Site 1.19 $1,460 $7, 824 $ 6,835 $6, 597 $5, 763 Oil Well Site 0.28 $1,460 $7, 824 $7, 587 $27, 534 $26, 700 **Well Site Program Weighted Average**  **e $22,302**  **$21,468** Gathering and Boosting Station 9.18 $30,907 $63, 747 $5 6,090 $6, 9 4 2 $6, 108

a. Assumes 67% reduction at 10,000 ppm leak definition, 89% reduction at 2,500 ppm leak definition and 94% reduction at 500 ppm leak reduction with the implementation of annual Method 21 monitoring. b. The capital cost s for ONG well sites includes the cost of impleme nting the monitoring program of $ 32 , 1 20 divided b y an average of 22 well sites per company. c . Annual cost s for ONG well sites and gathering and boosting stations include semiannual monit oring and repair costs and amortization of the capital cost s over 8 years at 7% interest. d . Recovery credits for ONG well sites were calculated assuming natural gas reductions based methane reductions, methane as 82.9% of natural gas composition, and the value of the natural gas recovered as $4 Mcf. e. The weighted average for well sites was calculated using the 2020 activity counts of 5,518 gas well site s and 16,562 oil well site s.***E.O. 12866 Review

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9 - 30 Fugitive Emissions **9.3.2 Existing Federal, State and Local Regulations**  **9.3.2.1 Federal Regulations that Specifically Require Control of VOC**  **Emissions** For each well site and gathering and boosting station , the EPA is proposing NSPS requirements that would require the development of one or more fugitive emissions monitoring plans that includes semiannual monitoring b y OGI and repair of leaking fugitive em ission components. **9.3.2.2 State and Local Regulations**  **that Specifically Require Control of VOC**

**Emissions** States may

have permitting restrictions on VOC emissions that may apply to an emissions source as a result of an operating, NSR NA, or PSD permit (e.g., on a case - by- case basis) based on air quality maintenance or improvement goals of an area. Permits specify what construction is allowed, what emission limits must be met, and often how the source must be operated. To assure that sources follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements. Permits specify what construction is allowed, what emission limits must be met, and often how the source must be operated. To assure that sources follow the permit requirements, permits also contain monitoring, recordkeeping, and reporting requirements. The State of Colorado has regulations that require annual leak inspections at all well sites, compressor stations upstream of the processing plant and storage v essels. These regulations allow OGI inspections, Method 21 or other “[d]ivision approved instrument based monitoring device or method” to detect leaks (Colorado Department of Public Health and Environment, Air Quality Control Commission, Regulation Number 7). The State of Wyoming, as part of its permitting guidance, requires facilities with VOC emissions greater than 4 tpy in the Upper Green River Basin, the Jonah - Pinedale Anticline Development Area and Normally Pressured Lance to conduct quarterl y leak em issions inspections, and OGI inspections are allowed in addition to Method 21 inspections or audio visual - olfactory

inspections (Wyoming Department of Environmental Quality , Oil and Gas Production Facilities, Chapter 6, Section 2 Permitting Guidance, September 2013).***E.O. 12866 Review

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9 - 31 Fugitive Emissions The State of Ohio requires operators to perform regular inspections to identify methane equipment leaks from horizontal wells and to repair leaks, where indicated. An owner or operator can either appl y for a general or traditional emissions permit. The State of Ohio’s updated existing leak detection general permit requires more frequent monitoring through use of infrared cameras and portable sampling instruments. Initially , operators must conduct quarterl y, rather than annual, leak monitoring. If minimal leaks are found, leak monitoring can be reduced to semiannual or annual inspections. If leaks are in excess of two percent, however, operators must continue quarterly

monitoring. When leaks are identified, corrective action must be taken within five day s (Ohio EPA General Permit Program; http://epa.ohio.gov/dapc/genpermit/genpermits.aspx#127854018 - recently- issued - model - general p ermits ). 

### 9.4 **Recommended RACT Level of Control** Based on our evaluation of available data obtained in the development of the 2015 proposed NSPS, peer review comments received on the equipment leaks white paper, and existing regulations that control VOC emissions from ONG production sites, we recommend that RACT for the collection of fugitive emission components at well sites and gathering and boosting station s be the implementation of a monitoring plan that includes semiannual monitoring using OGI and repair of components that are found to be leaking. A s discus sed in section 9.3.2.2 of this c hapter, existing state and local regulations already require fugitive emissions monitoring of ONG production sites. The monitoring techniques listed in these requirements include the use of either Method 21 or OGI to locate fugitive emissions from equipment and components. In addition, peer review comments received on the equipment leaks white paper show that some companies are voluntarily monitoring their production sites using OGI to eliminate leaks from equipment. Monitoring and repair of equipment and components using OGI or Method 21 are the most viable methods for reducing fugitive emissions from equipment leaks in the production segment of the ONG source category . Although both Wyoming and Ohio require quarterl y monitoring of components at production sites, we estimate the VOC cost of control for quarterly monitoring using OGI to be $3,160 per ton of VOC for natural gas well sites, $15,836 per ton of VOC for oil well sites, and $2,672 per ton of VOC for gatherin g and boosting station s considering natural gas savings.***E.O. 12866 Review

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9 - 32 Fugitive Emissions Based on the estimated VOC cost of control for quarterl y monitoring, we recommend that semiannual monitoring at well sites and gathering and boosting station s as RACT. The VOC cost of control for semiannual monitoring using OGI was estimated to be $2,111 per ton of VOC reduced for natural gas well sites, $11,460 per ton of VOC reduced for oil well sites , and $1,876 per ton of VOC for gathering and boosting station s consi dering natural gas savings. The cost of control for natural gas well sites and gathering and boosting stations is considered to be reasonable. For oil well sites, although the cost per ton of VOC reduced is higher than it is for natural gas wells sites and gathering and boosting stations, s ince publication of the “Oil and Natural Gas Sector Leaks” 142 white paper, additional emissions data have become available, including reporting ye ar 2013 data from GHGRP that confirm that fugitive emission sources are significant from ONG well sites and gathering and boosting stations . Notably , we further identified that many studies have shown a skewed distribution for emissions related to leaks, where a majority of emissions come from a minority of sources. 143 Commenter s on the white papers agreed that emissions from equipment leaks exhibit a skewed distribution, and pointed to other examples of data sets in which the majority of VOC emissions from leaks come from a minority

of components. Commenters note d that emitters are likel y due to random occurrences of low - probability but high - emissions conditions. Commenters also noted that in addition to variation in emissions per component, there can be significant variation in component counts and that these vary based on well production, site geograph y, type of gas, and companydetermined processing equipment. The recommended RACT is not intended to cover well sites with no or inherentl y fugitive VOC emissions. For well sites, the cost of control for a monitoring plan using Method 21 with a 10,000 ppm leak detection is generall y more costly than the use of OGI where there are a large number of equipment components to be monitored. The cost for a natural gas well site was estimated to be $3,051 per ton of VOC for annual monitorin g and $4,100 per ton of VOC for semiannual monitoring considering natural gas savings. The cost for an oil well site was estimated to be $18,826 per ton of VOC for annual monitoring and $19,759 per ton of VOC for annual monitoring considering natural gas s avings. As shown in section 9.3.1 of this c hapter, the cost of control for the 2,500 ppm and 500 ppm leak definition options are higher than the 10,000 ppm

142 Available at http://www.epa. gov/airquality/oilandgas/2014papers/20140415leaks.pdf . 143 For additional information, see the TSD.***E.O. 12866 Review

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9 - 33 Fugitive Emissions leak definition option. The use of a monitoring plan using Method 21 with a 10,000 ppm leak detectio n may , however, be a lower cost alternative to OGI where there are fewer equipment components to be monitored. For gathering and boosting station s, the cost of control for a monitoring plan using Method 21 with a 10,000 ppm leak detection is estimated to be $4,587 per ton of VOC removed for semiannual monitoring and $3,810 for annual monitoring considering natural gas savings. In summary , we recommend the following RACT for the collection of fugitive emission components at ONG well sites and gathering and boosting stations: RACT for the Collection of Fugitive Emission Components at ONG Well Sites and Gathering and Boosting Stations : We recommend th e i mplementation of a monitoring plan that includes semiannual monitoring using OGI and repair of components that are found to be leaking at well sites and gathering and boosting station s. We also recommend that each fugitive emission component repaired or replaced be re surveyed to ensure there is no leak after repair by

the use of either Method 21 or OGI within 15 days of finding fugitive emissions. 

### 9.5 **Factors to Consider in Developing Fugitive Emissions**  **RA CT**  **Procedures** T o ensure that fugitive emissions are properl y monitored and repaired (as necessary) under RACT requirements, we recommend that regulatory agencies specify OGI monitoring and equipment repair recordkeeping and reporting requirements to document compliance. **9.5.1 Monitoring Recommendations**  We recommend that regulatory agencies require a fugitive emissions OGI monitoring plan that covers fugitive emission component sources that includes basic required monitoring plan elements. We recommend that regulatory age ncies require both a corporate - wide and a site specific fugitive emissions OGI monitoring plan that covers the collection of fugitive emissions components at well sites and gathering and boosting station s. Alternativel y, regulatory agencies may decide to r equire a single OGI monitoring site - specific plan for each collection of fugitive emissions components at a well site and each collection of fugitive emissions components at a***E.O. 12866 Review

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9 - 34 Fugitive Emissions gathering and boosting station that covers the elements of both the corporate - wi de and site specific plans. We suggest that the corporate - wide monitoring plan include the following minimum elements: 1) F requency

for conducting survey s; 2) Technique for determining fu gitive emissions; 3) Manufacturer and model number of fugitive emissions dete ction equipment to be used; 4) Procedures and timeframes for identifying and repairing fugitive emissions components from which fugitive emissions are detected, including timeframes for fugitive emission compo nents that are unsafe to repair; 5) Procedures and ti meframes for verifying fugi tive emission component repairs; 6) Records that will be kept and the length of time records will be kept; 7) Verification that your optical gas imaging equipment meets the specification requirements; 8) Procedure for a daily

verification check; 9) Procedure for determining the operator’s maximum viewing distance from the equipment and how the operator will ensure that this distance is maintained; 10) Procedure for determining maximum wind speed during which monitoring ca n be performed and how the operator will ensure monitoring occurs onl y at w ind speeds below this threshold; 11) Procedures for conducting survey s; 12) Training and experience nee ded prior to performing survey s; and 13) Procedures for calibration and maintenance. Proce dures should compl y with those recommended b y the manufacturer. We suggest that you require the following minimum elements for the site - specific monitoring plan: 1) D eviations from your master plan; 2) Sitemap; and 3) Defined walking path (to ensure that all fugiti ve emissions components are within sight of the path and accounts for interferences).***E.O. 12866 Review

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9 - 35 Fugitive Emissions We recommend a monitoring survey of each collection of fugitive emissions components at a well site and collection of fugitive emissions components at a gathering and boo sting station be conducted at least semiannually after the initial survey

and that consecutive semiannual monitoring survey s be conducted at least four months apart. We recommend that the monitoring frequency be increased to quarterl y in the event that two consecutive semiannual monitoring survey s detect fugitive emissions at 1.0 percent or more of the fugitive emissions components at a well site or at 1.0 percent or more of the fugitive emissions components at a gathering and boosting station . We also reco mmend that the monitoring frequency be decreased to annual in the event that two consecutive semiannual survey s detect fugitive emissions at less than 1.0 percent of the fugitive emissions components at a well site, or at less than 1.0 percent of the fugitive emissions components at a gathering and boosting station . **9.5.2 Repair Recommendations**  We recommend that regulatory agencies require that any identified source of fugitive emissions be repaired or replaced as soon as practicable, but no later than 15 calendar day s after detection of the fugitive emissions. I f the repair or replacement is tec hnically infeasible or unsafe to repair during operation of the unit, the repair or replacement must be completed during the next scheduled shutdown or within 6 months, whichever is earlier. We also recommend that repaired or replaced fugitive emission components be required to be resurveyed as soon as practicable, but no later than 15 day s after completion of the repair or replacement, to ensure that there is no leak. For repairs that cannot be made during the monitoring survey when the fugitive emissions are initially

found, we recommend that regulatory agencies require that the operator resurvey the repaired fugitive emissions components using either Method 21 or OGI within 15 day s of finding such fugitive emissions. A fugitive emissions component is repa ired when th e OGI instrument shows no indication of visible emissions.***E.O. 12866 Review

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# Appendix***E.O. 12866 R eview

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Appendix: ii We include modular rule language in this appendix for our recommended RAC T for ONG source category sources. The intent of this language is to provide regulation language that states can easily adapt for use. Although we include model rule language for closed vent sy stems, control devices and performance tests (that apply across several model rule requi rements for sources ), it is acknowledged that states may have existing similar language in their programs that they may want to use in lieu of the model language provided. The model rule language does not specify rule effective dates or compliance dates because those dates will be determined by the state or local government regulatory authority . State and local government agencies are encouraged to search this model rule language for places where the “regulatory

authority” will need to specify dates (e.g. , effective date, compliance date) b y searching for (“regulatory authority” ) in the model rule language.***E.O. 12866 R eview

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Appendix: iii 

### Appendix: Table of Contents A Storage Vessels: VOC Emission Control Requirements ................................ ................ A - 1 A.1 Applicability ................................ ................................ ................................ .................. A - 1 A.2 What V OC Emission Control Requirements Apply to Storage Vessels? ..................... A - 1 A.3 Initial Compliance Demonstration Requirements ................................ ......................... A - 3 A.4 Continuous Compliance Demonstration Requirements ................................ ................ A - 4 A.5 Recordkeeping and Reporting Requirements ................................ ................................ A - 8 A.6 Definitions ................................ ................................ ................................ ................... A - 10 B Pneumatic Controllers: VOC Emission Control Requirements ................................ ............... B - 1 B.1 Applicability ................................ ................................ ................................ .................. B - 1 B.2 What VOC Emission Control Requirements Apply to Pneumatic Controllers? ........... B - 1 B.3 Initial Compliance Demonstration Requirements ................................ ......................... B - 2 B.4 Continuous Compliance Demonstration Requirements ................................ ................ B - 3 B.5 Recordkeeping and Reporting Requirements ................................ ................................ B - 4 B.6 Definitions ................................ ................................ ................................ ..................... B - 5 C Compressors: VOC Emissions Control Requirements ................................ ........................... C - 1 C.1 Applicability ................................ ................................ ................................ .................. C - 1 C.2 What V OC Emission Control Requirements Apply to Centrifugal Compressors? ....... C - 1 C.3 What VOC Emission Control Requirements Apply to Reciprocating Compressors? .. C - 2 C.4 Initial Compliance Demonstration Requirements ................................ ......................... C - 3 C.5 Continuous Compliance Demonstration Requirements ................................ ................ C - 5 C.6 Recordkeeping and Reporting Requirements ................................ ................................ C - 9 C.7 Definitions ................................ ................................ ................................ ................... C - 11 D Cover and Closed Vent Sy stem Requirements ................................ ................................ ..... D - 1 D.1 What Are My

Cover and Closed Vent Sy stem Requirements? ................................ ..... D - 1 D.2 What Are My

Initial and Continuous Cover and Closed Vent Sy stem Inspection and Monitoring Requirements? ................................ ................................ ............................ D - 3 E VOC Emission Control Device Requirements ................................ ................................ ...... E - 1 E.1 Initial Control Device Compliance Requirements ................................ ......................... E - 1 E.2 Continuous Control Device Monitoring Requirements ................................ .................. E - 3 F Performance Test Procedures ................................ ................................ ....................... F - 1 G Equipment Component VOC Leaks at Natural Gas Processing Plants ................................ .... G - 1***E.O. 12866 R eview

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Appendix: iv G.1 Applicability ................................ ................................ ................................ .................. G - 1 G.2 What VOC Emission Control Requirements Apply to Equipment Components at an Onshore Natural Gas Processing Plant? ................................ ................................ ........ G - 1 G.3 What Exceptions to the Equipment L eak VOC Emission Control Requi rements Apply at Onshore Natural Gas Processing Plants? ................................ ................................ ...... G - 2 G.4 How Do I Demonstrate Initial and Continued Compliance with the VOC Emission Control Requirements for Equipment Components Subject to Control Requirements at Onshore Natural Gas Processing Plants? ................................ ................................ ...... G - 4 G.5 Equipment Component VOC Emission Control Requirements ................................ .... G - 5 G.5.1 VOC Emission Control Requirements: General ................................ .............. G - 5 G.5.2 What Equipment Component VOC Emission Control Requirements that Apply to Pumps in L ight Liquid Service? ................................ ................................ .... G - 7 G.5.3 What are the Equipment Component VOC Emission Control Requirements that Apply to Compressors? ................................ ................................ .............. G - 11 G.5.4 Wh at Equipment Component VOC Emi ssion Control Requirements Apply to Pressure Relief Devices in Gas/Vapor Service? ................................ ............ G - 13 G.9.5 What Equipment Component VOC Emi ssion Control Requirements Apply to Sampling Connection Systems? ................................ ................................ .. G - 14 G.5.6 What Equipment Component V OC Emission Control Require ments Apply to Open Ended Valves or L ines? ................................ ................................ ............. G - 15 G.5.7 What Equipment Component VOC Emi ssion Control Requirements Apply to Valves in Gas/Vapor Service and in Light L iquid Service? ............................ G - 16 G.5.8 What Equipment Component VOC Emi ssion Control Requirements Apply to Pumps, Valves, and Connectors in Heav y Li quid Service and Pressure Relief Devices in Light Liquid or Heavy L iquid Service? ................................ ....... G - 19 G.5.9 What Delay

of Repair of Equipment Components Requirements Apply When Equipment Component Leaks Have Been Detected? ................................ ..... G - 19 G.5.10 What VOC Emission Control Requirements Apply for Closed Vent Sy stems and Control Devices ? ................................ ................................ ...................... G - 21 G.5.11 What VOC Emission Control Requirements Apply to Connectors in Gas/Vapor Service and in Light Liquid Service? ................................ ........................... G - 24 G.6 Alternative Standards ................................ ................................ ................................ .. G - 28 G.6.1 Alternative Standards for Valves

— Allowable Percentage of Valves Leaking .. G - 28 G.6.2 Alternative Standards for Valves

— Skip Period Leak Detection and Repair ..... G - 29 G.7 Equipment L eak Test Methods and Procedures ................................ .......................... G - 30 G.8 Recordkeeping and Reporting Requirements ................................ .............................. G - 35 G.9 Definitions ................................ ................................ ................................ ................... G - 44***E.O. 12866 R eview

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Appendix: v H Pneumatic Pumps: VOC Emissions Control Requirements ................................ .................... H - 1 H.1 Applicability ................................ ................................ ................................ .................. H - 1 H.2 What V OC Emission Reduction Requirements Apply to Natural Gas - Driven Pneumatic Pumps? ................................ ................................ ................................ .......................... H - 1 H.3 Initial Compliance Demonstration Requirements ................................ ......................... H - 3 H.4 Continuous Compliance Demonstration Requirements ................................ ................ H - 3 H.5 Recordkeeping and Reporting Requirements ................................ ................................ H - 7 H.6 Definitions ................................ ................................ ................................ ..................... H - 8 I Fugitive Emissions Components VOC Emissions Control Requirements ................................ .. I - 1 I.1 Applicability ................................ ................................ ................................ .................... I - 1 I.2 What VOC Emission Control Requirements Apply to the Collection of Fugitive Emission Components at a Well Site and a Compressor Station? ................................ .. I - 1 I.3 Initial Compliance Demonstration ................................ ................................ .................. I - 5 I.4 Continuous Compliance Demonstration ................................ ................................ ......... I - 5 I.5 Recordkeeping and Reporting Requirements ................................ ................................ .. I - 6 I.6 Definitions ................................ ................................ ................................ ....................... I - 7***E.O. 12866 Review

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Appendix : A - 1 

### A **Storage Vessels: VOC Emission Control Requirements**  **A.1 Applicability**  (a) The VOC emissions co ntrol requirements of section A apply to each storage vessel located in the oil and natural gas sector (excluding distribution) that has the potential for VOC emissions equal to or greater than 6 tpy . The potential for VOC emissions must be calculated using a generally

accepted model or calculation methodology , based on the maximum average daily throughput determined for a 30 - day period of production prior to the applicable emission determinati on deadline established by your regulatory

authority . The determination may take into account requirements under a legally and practically

enforceable limit in an operating permit or other requirement established under a federal, state, local or tribal authority. Any vapor from the storage vessel that is recovered and routed to a process through a VRU designed and operated as specified in this section is not required to be included in the determination of VOC potential to emit for purposes of determining applicability, provided you comply with the requirements in section A.2. (b) The storage vessel VOC emission control requirements specified in this section do not apply to storage vessels subject to and controlled in accordance with the requirements for storage vessels in 40 CFR part 60, subpart Kb, 40 CFR part 63, subparts G, CC, HH, or WW. 

### A.2 **What VOC Emission Control Requirements Apply to Storage V essels?**  For each storage vessel, you must comply with the VOC emissions control requirements of paragraphs (a) through (e) in this section by the compliance date established by your regulatory

authority . Requirements for storage vessels removed from service are presented in paragraph (f) of this section. (a) You must reduce VOC emissions from each storage vessel by 95 percent. (b) (1) Except as required in paragraph (b)(2) of this section, if you use a control device to reduce emissions, you must equip the storage vessel with a cover that meets the requirement***E.O. 12866 R eview

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Appendix: A - 2 of section D.1(a), that is connected through a closed vent s ys tem that meets the requirements of section D.1(b) and routed to a control device that meets the conditions specified in paragraph (b)(3)(i) and (ii) of this section. As an alternative to routing the closed vent sy stem to a control device, you may route the closed vent s ys tem to a process. (2) If you use a floating roof to reduce emissions, you must meet the requirements of 40 CFR 60.112b(a)(1) or (2) and the relevant monitoring, inspection, recordkeeping, and reporting requirements in 40 CFR part 60 , subpart Kb. (3) (i) For each control device used to meet the VOC emission reduction control requirements in paragraph (a), you must comply with the applicable control device compliance requirements of section E.1 and install and operate a continuous parameter monitoring sy stem for each control device as specified in section E.2(c) through (f), except as provided for in section E.2(b). (ii) You must operate each control device used to comply with this rule at all times when gases, vapors, and fumes are vented from your storage vessel through a closed vent s ys tem to a control device. You may

vent more than one source to a control device. (c) You must demonstrate initial compliance with the VOC emission reduction requirements that appl y t o each storage vessel as required in section A.3. (d) You must demonstrate continuous compliance with the VOC emission control requirements that appl y t o each storage vessel as required b y section A.4. (e) You must perform the required recordkeeping and reporting as required by section A.5. (f) Requirements for storage vessels that are removed from service or returned to service . If you are the owner or operator of a storage vessel subject to the VOC emission control requirements that is removed from service, you must comply with paragraphs (f)(1) through (3) of this section . A storage vessel is not an affected source under this s e ction for the period that it is removed from service .***E.O. 12866 R eview

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Appendix: A - 3 (1) For a storage vessel to be removed from service, you must comply with the requirements of paragraph (f)(1)(i) and (ii) of this section. (i) You must completely

empty and degas the storage vessel, su ch that the storage vessel no longer contains crude oil, condensate, produced water or intermediate hydrocarbon liquids. A storage vessel where liquid is left on walls, as bottom clingage or in pools due to floor irregularity is considered to be completel y empty . (ii) You must submit a notification in your next annual report, identifying all storage vessels removed from service during the reporting period and the date of its removal from service . (2) If the storage vessel subject to VOC emission control req uirements identified in paragraph (f)(1) of this section is returned to service during the reporting year , you must compl y with paragraphs (f)( 3 ) of this section. ( 3 ) You must submit a notification in your next annual report identifying each storage vessel that has been returned to service and the date of its return to service . 

### A.3 **Initial Compliance Demonstration Requirements** You must demonstrate initial compliance by the compliance date specifi ed by your regulatory

authority b y demonstrating compliance wi th the VOC emission control requirements for each storage vessel complying with section A.2 by compl yi ng with the requirements in paragraphs (a) through (g) of this section. (a) You determine the potential VOC emission rate as specified in section A.1(a). (b) You reduce VOC emissions from each storage vessel subject to VOC emission control requirements by

95 percent or greater as required in section A.2 and as demonstrated by section F. (c) If you use a control device to reduce emissions, you equip your st orage vessel with a cover that meets the requirements of section D.1(a) that is connected through a closed vent sy stem that meets the requirements of section D.1(b) and is routed to a control device that meets***E.O. 12866 R eview

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Appendix: A - 4 the requirements of section E.1. As an alternative to routing the closed vent sy stem to a control device, you may route the closed vent s ys tem to a process. (d) You conduct an initial performance test as required in section F within 180 day s after the effective date of this rule, as established b y yo ur regulatory authority . (e) You conduct the initial cover and closed vent sy stem inspections required in section D.2 within 180 day s after the effective date of this rule as established b y yo ur regulatory authority . (f) You submit the initial annual report for your storage vessels as required in section A.5(b). (g) You maintain the records as specified in section A.5(a). 

### A.4 **Continuous Compliance Demonstration Requirements** You have demonstrated continuous compliance for each storage vessel subject to the VOC emission control requirements in section A.2 by meeting the requirements in paragraphs (a) through (c) of this section. (a) For each storage vessel subject to VOC emissi on reduction requirements, you must demonstrate continuous compliance according to paragraphs (b) and (c) of this section. (b) You must reduce VOC emissions from the storage vessel by 95 percent or greater. (c) For each control device used to reduce emissi ons, you must demonstrate continuous compliance with the performance requirements of section A.2(a) using the procedure s specified in paragraphs (c)(1) through (7 ) of this section, as applicable. If you use a condenser as the control device to achieve the requirements specified in section A.2(a), you demonstrate compli ance according to paragraph (c)(8 ) of this section. You may switch between c ompliance with paragraphs (c)(1) through (7 ) of this section and compliance with paragraph (c)(8 ) of this section on ly

after at least 1 year of operation in compliance with the selected approach. You***E.O. 12866 R eview

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Appendix: A - 5 must provide notification of such a change in the compliance method in the next annual report, as required in section A.5(b), following the change. (1 ) You must operate be low (or above) the site specific maximum (or minimum) parameter value established according to the requirements of section E.2(f)(1). (2 ) You must calculate the daily average of the applicable monitored parameter in accordance with section E.2(e) except th at the inlet gas flow rate to the control device must not be averaged. (3 ) Compliance with the operating parameter limit is achieved when the daily average of the monitoring parameter value calculated under paragraph (c)(2) of this section is either equal to or greater than the minimum monitoring value or equal to or less than the maximum monitoring value es tablished under paragraph (c)(1 ) of this section. When performance testing of a combustion control device is conducted b y the device manufacturer as spe cified in section F(d), compliance with the operating parameter limit is achieved when the criteria in section F(e) are met. (4 ) You must operate the continuous monitoring sy stem required in section E.2(a) at all times the source is operating, except for p eriods of monitoring sy stem malfunctions, repairs associated with monitoring s ys tem malfunctions, and required monitoring sy stem quality assurance or quality control activities (including, as applicable, s ys tem accuracy audits and required zero and span ad justments). A monitoring s ys tem malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring s ys tem to provide valid data. Monitoring s ys tem failures that are caused in part by poor maintenance or careless operation are not m alfunctions. You are required to complete monitoring s ys tem repairs in response to monitoring sy stem malfunctions and to return the monitoring sy stem to operation as expeditiously

as practicable. (5 ) You may

not use data recorded during monitoring s ys tem m alfunctions, repairs associated with monitoring s ys tem malfunctions, or required monitoring sy stem quality assurance or control activities in calculations used to report emissions or operating levels. You***E.O. 12866 R eview

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Appendix: A - 6 must use all the data collected during all other re quired data collection periods to assess the operation of the control device and associated control sy stem. (6 ) Failure to collect required data is a deviation of the monitoring requirements, except for periods of monitoring sy stem malfunctions, repairs as sociated with monitoring s ys tem malfunctions, and required quality monitoring s ys tem quality assurance or quality

control activities (including, as applicable, sy stem accuracy audits and required zero and span adjustments). (7 ) If you use a combustion control device to meet the requirements of section A.2(a) and yo u demonstrate compliance using the test procedures specified in section F(b), you mu st comply with paragraphs (c)(7)(i) through (iv ) of this section. (i ) A pilot flame must be present at all times of operation. (ii ) Devices must be operated with no visible emissions, except for periods not to exceed a total of one minute during any 15 minute period. A visible emissions test using section 11 of Method 22, 40 CFR part 60, appendix A, must be performe d at least once every calendar month, separated b y at least 15 days between each test. The observation period shall be 15 minutes. (iii ) Devices failing the visible emissions test must follow manufacturer's repair instructions, if available, or best comb ustion engineering practice as outlined in the unit inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair and maintenance activities for each unit must be recorded in a maintenance and repair log and must be available for inspection. (iv ) Following return to operation from maintenance or repair activity , each device must pass a Method 22, 40 CFR part 60, appendix A, visual observation as described in paragraph (c)(2)(vii)(B) of this section. (8 ) If you use a cond enser as the control device to achieve the percent reduction performance requirements specified in section A.2(a), you must demonstrate compliance using the proce dures in paragraphs (c)(8)(i) through (v ) of this section.***E.O. 12866 R eview

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Appendix: A - 7 (i ) You must establish a site - speci fic condenser performance curve according to section E.2(f)(2). (ii ) You must calculate the daily average condenser outlet temperature in accordance with section E.2(e). (iii ) You must determine the condenser efficiency for the current operating day using the daily average condenser outlet temperature calculated under paragraph (c)(8)(ii ) of this section and the condenser performance curve establi shed under paragraph (c)(8)(i ) of this section. (iv ) You must calculate the 365 - day rolling average TOC emission reduction, as appropriate, from the condenser efficiencies as det ermined in paragraph (c)(8)(iii ) of this section. (A) If you have less than 120 days of data for determining average TOC emission reduction, you must calculate the average TOC emission reduc tion for the first 120 days of operation. You have demonstrated compliance with the overall 95 percent reduction requirement if the 120 - day

average TOC emission reduction is equal to or greater than 95 percent. (B) After 120 day s and no more than 364 day s of operation, you must calculate the average TOC emission reduction as the TOC emission reduction averaged over the number of day s of operation where you have data. You have demonstrated compliance with the overall 95 percent reduction requirement, if the average TOC emission reduction is equal to or greater than 95 percent. (v ) If you have data for 365 days or more of operation, you have demonstrated compliance with the TOC emission reduction if the rolling 365 - day average TOC emission reductio n calculated in paragraph (c)(8)(4 ) of this section is equal to or greater than 95 percent. (d) You must submit the annual report required by section A.5(b) and maintain the records as specified in section A.5(a).***E.O. 12866 R eview

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Appendix: A - 8 

### A.5 **Recordk ee**  **ping and Reporting Requirements** (a) Recordkeeping requirements. For each storage vessel, you must maintain the records identified in paragraphs (a)(1) through (10) of this section, as applicable. (1) If required to reduce emissions by complying with sectio n A.2(a), the records specified in paragraphs (a)(6) through (8) of this section and section D.2, as applicable. (2) Records of each VOC emissions determination for each storage vessel made under A.1(a) including identification of the model or calculation methodology used to calculate the VOC emission rate. (3) Records of deviations in cases where the storage vessel was not operated in compliance with the requirements specified in sections A.2, D, E and F, as applicable. (4) For storage vessels that are ski d - mounted or permanently attached to something that is mobile (such as trucks, railcars, barges or ships), records indicating the number of consecutive day s that the vessel is located at a site in the oil and natural gas production segment, natural gas pro cessing segment or natural gas transmission and storage segment. If a storage vessel is removed from a site and, within 30 day s, is either returned to or replaced by another storage vessel at the site to serve the same or similar function, then the entire period since the original storage vessel was first located at the site, including the day s when the storage vessel was removed, must be added to the count towards the number of consecutive day s. (5) Records of the identification and location of eac h storag e vessel subject to emission control requirements. (6) Records of each closed vent sy stem inspection required under section D.2(a) and (b). (7) A record of each cover inspection required under section D.2(c). (8) If you are subject to the bypass requirements of section D.2(d), a record of each inspection or a record each time the key is checked out or a record of each time the alarm is sounded.***E.O. 12866 R eview

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Appendix: A - 9 (9) For each carbon adsorber installed on a storage vessel, records of the schedule for carbon replacement (as det ermined b y the design anal ys is requirements of section E.1(a)(2)) and records of each carbon replacement as specified in section E.1(c)(1). (10) For each storage vessel subject to the control device requirements of section E.2(c) and (d), records of the in spections, including any corrective actions taken, the manufacturers' operating instructions, procedures and maintenance schedule as specified in section E.2(h). Records of section 11, EPA Method 22, 40 CFR part 60, appendix A results, which include: company , location, company representative (name of the person performing the observation), sky conditions, process unit (ty pe of control device), clock start time, observation period duration (in minutes and seconds), accumulated emission time (in minutes and s econds), and clock end time. You may create your own form including the above information or use Figure 22 - 1 in EPA Method 22, 40 CFR part 60, appendix A. Control device manufacturer operating instructions, procedures and maintenance schedule must be avail able for inspection. (b) Reporting requirements . For storage vessels, you must submit annual reports containing the information specified in paragraphs (b)(1) through (6 ) of this section. (1) An identification, including the location, of eac h storage vessel subject to VOC emission control requirements. The location of the storage vessel shall be in latitude and longitude coordinates in decimal degrees to an accuracy and precision of five (5) decimals of a degree using the North American Datum of 1983. (2) Documentation of the VOC emission rate determination according to section A.1(a). (3) Records of deviations specified in paragraph (a)(3) of this section that occurred during the reporting period. (4) A statement that you have met the requirements spec ified in section A.3(b) and (c). (5) You must identify

each storage vessel that is removed from service during the reporting period as specified in section A.2(f)(1) , including the date the storage vessel was removed from service .***E.O. 12866 R eview

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Appendix: A - 10 (6) You must identify

ea ch storage vessel returned to service during the reporting period as specified in section A.2(f)( 3 ) , including the date the storage vessel was returned to service. . 

### A.6 **Definitions** Condensate means h ydrocarbon liquid separated from natural gas that condens es due to changes in the temperature, pressure, or both, and remains liquid at standard conditions. Gas processing plant process unit means equipment assembled for the extraction of natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or other operations associated with the processing of natural gas products. A process unit can operate independ entl y if supplied with sufficient feed or raw materials and sufficient storage facilities for the products. Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. A Joule - Thompson valve, a dew point depression valve, or an isolated or standalone Joul e - Thompson skid is not a natural gas processing plant. Natural gas transmission means the pipelines used for the long distance transport of natural gas (excluding processing). Specific equipment used in natural gas transmission includes the land, mains, valves, meters, boosters, regulators, storage vessels, dehydrators, compressors, and their driving units and appurtenances, and equipment used for transporting gas from a production plant, delivery point of purchased gas, gathering s ys tem, storage area, or o ther wholesale source of gas to one or more distribution area(s). Pressure vessel means a storage vessel that is used to store liquids or gases and is designed not to vent to the atmosphere as a result of compression of the vapor headspace in the pressure vessel during filling of the pressure vessel to its design capacity . Produced water means water that is extracted from the earth from an oil or natural gas well, or that is separated from crude oil, condensate, or natural gas after extraction.***E.O. 12866 R eview

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Appendix: A - 11 Removed from service means that a storage vessel subject to the VOC control requirements has been physicall y isolated and disconnected from the process for a purpose other than maintenance. Returned to service means that a storage vessel subject to the VOC requirement s that was removed from service has been: (1) Reconnected to the original source of liquids or has been used to replace any storage vessel subject to the VOC requirements; or (2) Installed in any location covered b y this rule and introduced with crude oil, condensate, intermediate hydrocarbon liquids or produced water. Routed to a process or route to a process means the emissions are conveyed via a closed vent sy stem to any enclosed portion of a process where the emissions are predominantly recycled and/or consumed in the same manner as a material that fulfills the same function in the process and/or transformed b y chemical reaction into materials that are not regulated materials and/or incorporated into a product; and/or recovered. Salable quality gas mean s natural gas that meets the flow line or collection sy stem operator specifications, regardless of whether such gas is sold. Storage vessel means a tank or other vessel that contains an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water, and that is constructed primarily of nonearthen materials (such as wood, concrete, steel, fiberglass, or plastic) whi ch provide structural support. A well completion vessel that receives recovered liquids from a well after startup of production following flowback for a period which exceeds 60 day s is considered a storage vessel under this rule. A tank or other vessel shall not be considered a storage vessel if it has been removed from service in accordance with the requirements of (f)(2) of this section until such time as such tank or other vessel has been returned to service. For the purposes of this rule, the following are not considered storage vessels: (1) Vessels that are skid - mounted or permanently attached to something that is mobile (such as trucks, railcars, barges or ships), and are intended to be located at a site for less than 180 consecutive day s. If you do no t keep or are not able to produce records, as required b y section***E.O. 12866 R eview

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Appendix: A - 12 A.5(a)(4), showing that the vessel has been located at a site for less than 180 consecutive day s, the vessel described herein is considered to be a storage vessel from the date the original vessel was first located at the site. This exclusion does not apply to a well completion vessel as described above. (2) Process vessels such as surge control vessels, bottoms receivers or knockout vessels. (3) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere. Underground storage vessel means a storage vessel stored below ground.***E.O. 12866 Review

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Appendix : B - 1 

### B **Pneumati c**  **Controllers: VOC Emission Control Requirements**  **B.1 Applicability**  The VOC emission control requirements specified in section B. 2 appl y to the pneumatic controllers specified in paragraphs (a) and (b) of this section. (a) For natural gas processing plants, each pneumatic controller, which is a single continuous bleed natural gas - driven pneumatic controller. (b) For each pneumatic controller located between the wellhead and natural gas processing plant or point of custody transfer to an oil pipeline , which is a single continuous bleed natural gas - driven pneumatic controller operating at a natural gas bleed rate greater than 6 standard cubic feet per hour. 

### B.2 **What VOC Emission Control Requirements Apply to Pneumatic C**  **ontrollers?** For each pneumatic controller, you must compl y with requirements based on natural gas as a surrogate for VOC, as specified in either paragraph (b)(1) or (c)(1) of this section, as applicable. Pneumatic controllers meeting the conditions in paragraph (a) of this section are exempt from these requirements. (a) The requirements of paragraph (b)(1) or (c)(1) of this section are not required if you determine that the use of a pneumatic controller with a bleed rate greater than 6 standard cubic feet per hour is required based on functional nee ds, including but not limited to response time, safety and positive actuation. However, you must tag such pneumatic controller with the date that the pneumatic controller is required to compl y with the model rule (as established by your regulatory

authority) that allows traceability to the records for that pneumatic controller, as required in section B.5(a)(2). (b)(1) Each pneumatic controller subject to VOC emissions control requirements at a natural gas processing plant must have a bleed rate of zero.***E.O. 12866 R eview

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Appendix : B - 2 (2) Each pneumatic controller subject to VOC emissions control requirements at a natural gas processing plant must be tagged with the date that the pneumatic controller is required to comply with the model rule (as established b y yo ur regulatory authority) th at allows traceability to the records for that pneumatic controller as required in section B.5(a)(4) (c)(1) Each pneumatic controller subject to VOC emissions control requirements at a location between the wellhead and a natural gas processing plant or the point of custody transfer to an oil pipeline must have a bleed rate less than or equal to 6 standard cubic feet per hour. (2) Each pneumatic controller subject to VOC emission control requirements at a location between the wellhead and a natural gas proce ssing plant or the point of custody transfer to an oil pipeline must be tagged with the date that the pneumatic controller is required to comply with the model rule (as established by your regulatory

authority) that allows traceability to the records for that controller as required in section B.5(a)(3). (d) You must demonstrate initial compliance by the compliance date specified by your regulatory

authority b y demonstrating compliance with the VOC emission reduction requirements that appl y t o pneumatic controllers as required by section B.3. (e) You must demonstrate continuous compliance with VOC emission reduction requirements that appl y t o pneumatic controllers as required b y section B.4. (f) You must perform the required recordkeeping and reporting as req uired by section B.5. 

### B.3 **Initial Compliance Demonstration Requirements** You must demonstrate initial compliance with the VOC emission control requirements for your pneumatic controller by complying with the requirements specified in paragraphs (a) through (f) of this section by the compliance date specified by your regulatory

authority , as applicable.***E.O. 12866 R eview

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Appendix : B - 3 (a) You must demonstrate initial compliance b y maintaining records as specified in section B.5(a)(2) of your determination that the use of a pneumatic control ler with a bleed rate greater than 6 standard cubic feet of gas per hour is required as specified in section B.2(a). (b) You own or operate a pneumatic controller located at a natural gas processing plant and your pneumatic controller is driven by a gas other than natural gas and therefore emits zero natural gas. (c) You own or operate a pneumatic controller located between the wellhead and a natural gas processing plant and the manufacturer's design specifications indicate that the controller emits less th an or equal to 6 standard cubic feet of gas per hour. (d) You must tag each pneumatic controller according to the requirements of section B.2(b)(2) or (c)(2). (e) You must include the information in paragraph (a) of this section and a listing of the pneumatic controller sources specified in paragraphs (b) and (c) of this section in the initial annual report according to the requirements of section B.5(b) (f) You must maintain the records as specified in section B.5(a) for each pneumatic controller subject t o VOC emission control requirements. 

### B.4 **Continuous Compliance Demonstration Requirements** For each pneumatic controller, you must demonstrate continuous compliance according to paragraphs (a) through (c) of this section. (a) You must continuously operate e ach pneumatic controller as required in section B.2(a), (b), or (c). (b) You must submit the annual report as required in section B.5(b). (c) You must maintain records as required in section B.5(a).***E.O. 12866 R eview

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Appendix : B - 4 

### B.5 **Recordk eeping and Reporting Requirements**  (a) Recordkeeping requirements . For each pneumatic controller, you must maintain the records identified in paragraphs (a)(1) through (5) of this section. (1) Records of the date, location and manufacturer specifications for each pneumatic controller. (2) If ap plicable, a record of the demonstration that the use of a pneumatic controller with a natural gas bleed rate greater than 6 standard cubic feet per hour is required and the reasons why . (3) If the pneumatic controller is not located at a natural gas proces sing plant, records of the manufacturer's specifications indicating that the controller is designed such that natural gas bleed rate is less than or equal to 6 standard cubic feet per hour. (4) If the pneumatic controller is located at a natural gas proces sing plant, records of the documentation that the natural gas bleed rate is zero. (5) Records of deviations in cases where the pneumatic controller was not operated in compliance with the requirements specified in section B.2. (b) Reporting requirements . Y ou must submit annual reports containing the information specified in paragraphs (b)(1) through (3) of this section. (1) An identification of each existing pneumatic controller and each pneumatic controller constructed, modified or reconstructed during the reporting period, including the identification information specified in section B.2(b)(2) or (c)(2). (2) If applicable, documentation that the use of a pneumatic controller with a natural gas bleed rate greater than 6 standard cubic feet per hour is required and the reasons why . (3) Records of deviations specified in paragraph (a)(5) of this section that occurred during the reporting period.***E.O. 12866 R eview

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Appendix : B - 5 

### B.6 **Definitions** Bleed rate means the rate in standard cubic feet per hour at which natural gas is continuously

vente d (bleeds) from a pneumatic controller. Continuous bleed means a continuous flow of pneumatic supply natural gas to the process control device (e.g., level control, temperature control, pressure control) where the supply gas pressure is modulated by the process condition, and then flows to the valve controller where the signal is compared with the process set - point to adjust gas pressure in the valve actuator. Intermittent/snap - action pneumatic controller means a pneumatic controller that vents non - continuously . Natural gas - driven pneumatic controller means a pneumatic controller powered b y pressurized natural gas. Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, f ractionation of mixed natural gas liquids to natural gas products, or both. A Joule - Thompson valve, a dew depression valve, or a standalone Joule - Thompson skid is not a natural gas processing plant. Non - natural gas - driven pneumatic controller means an instrument that is actuated using other sources of power than pressurized natural gas; examples include solar, electric, and instrument air. Pneumatic controller means an automated instrument used for maintaining a process condition such as liquid level, press ure, delta - pressure and temperature.***E.O. 12866 Review

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Appendix : C - 1 

### C **Compressors: VOC Emissions Control Requirements C.1**  **Applicability** (a) Centrifugal c ompressors . Each centrifugal compressor, which is a single centrifugal compressor using wet seals located between the wellhead and point of custody transfer to the natural gas transmission and storage segment . A centrifugal compressor located at a well site, or an a djacent well site and servicing more than one well site, is not a source subject to VOC requirements under this rule. (b) Reciprocating c ompressors . Each reciprocating compressor located between the wellhead and point of custody transfer to the natural gas transmission and storage segment . A reciprocating compressor located at a well site, or an adjacent well site and servicing more than one well site, is not a source subject to VOC requirements under this rule. 

### C.2 **What VOC Emission Control R** **equirements Ap**  **ply to C entrifuga**  **l C**  **ompressors?** For each centrifugal compressor, you must comply with the VOC emissions control requirements in paragraphs (a) through (g). (a) You must reduce VOC emissions from each centrifugal compressor wet seal fluid degassing s ys tem b y 95.0 percent or greater. (b) If you use a control device to reduce emissions, you must equip the wet seal fluid degassing s ys tem with a cover that meets the requirements of section D.1(a) . The cover must be connected through a closed vent s ys tem that mee ts the requirements of section D.1(b) and the closed vent s ys tem must be routed to a control device that meets the conditions specified in paragraph (c) of this section. As an alternative to routing the closed vent system to a control device, you may route the closed vent s ys tem to a process.***E.O. 12866 R eview

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Appendix : C - 2 (c) For each control device used to compl y with the VOC emission reduction control requirements in paragraph (a), you must install and operate a continuous parameter monitoring sy stem for each control device as specif ied in section E.2(a) through (f), except as provided for in section E.2(b). (d) You must operate each control device installed on your centrifugal compressor in accordance with the requirements specified in paragraphs (d)(1) and (2) of this section. (1) Y ou must operate each control device used to comply with this rule at all times when gases, vapors, and fumes are vented from the wet seal fluid degassing s ys tem through the closed vent sy stem to the control device. You may vent more than one source to a si ngle control device. (2) For each control device monitored in accordance with the requirements of section E.2(a) through (f), you must demonstrate continuous compliance according to the requirements of section C.5(a)(2), as applicable. (e) You must demonstrate initial compliance with the VOC emission reduction requirements that appl y t o each centrifugal compressor as required b y section C.4(a). (f) You must demonstrate continuous compliance with the VOC emission control requirements that appl y t o each centrifugal compressor as required by section C.5(a). (g) You must perform the required recordkeeping and reporting as required by section C.6(a)(1) and (b)(1), as applicable. 

### C.3 **What VOC Emission Control R** **equirements Apply to R** **eciprocati ng**  **C ompressors?**  You must comply

with the VOC emission control requirements in paragraphs (a) through (d) of this section for each reciprocating compressor. (a) You must replace the reciprocating compressor rod packing according to either paragraph (a)(1) or (2) of this sectio n or you must comply with paragraph (a)(3) of this section .***E.O. 12866 R eview

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Appendix : C - 3 (1) Before the compressor has operated for 26,000 hours. The number of hours of operation must be continuously monitored beginning on the compliance date for your reciprocating compressor as specified b y your regulatory authority , or the date of the most recent reciprocating compressor rod packing replacement, whichever is later. (2) Prior to 36 months from the date of the most recent rod packing replacement, or 36 months from the complian ce date for a reciprocating compressor for which the rod packing has not yet been replaced. (3 ) Collect the VOC emissions from the rod packing using a rod packing emissions collection sy stem which operates under negative pressure and route the rod packing emissions to a process through a closed vent sy stem that meets the requirements of section D.1(b) . (b) You must demonstrate initial compliance with requirements that appl y t o reciprocating compressor sources as required b y s ection C.4(b). (c) You must demo nstrate continuous compliance with requirements that apply to reciprocating compressor sources as required b y s ection C.5(b). (d) You must perform the required recordkeeping and reporting as required by section C.6(a)(2) and (b)(2). 

### C.4 **Initial Compliance Demonstration Requirements**  You must demonstrate initial compliance by the compliance date specified by your regulatory

authority b y demonstrating compliance with the VOC emission control requirements for each centrifugal compressor b y compl yi ng with the re quirements in paragraph (a) of this section, and for each reciprocating compressor b y complying with the requirements in paragraph (b) of this section. (a) Centrifugal c ompressors . You have achieved initial compliance with the VOC emission control requirements for each centrifugal compressor if you have complied with paragraphs (a)(1) through (6) of this section.***E.O. 12866 R eview

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Appendix : C - 4 (1) You reduce VOC emissions from each centrifugal compressor wet seal fluid degassing s ys tem by

95 percent or greater as required in sec tion C.2 and as demonstrated by section F. (2) You use a control device to reduce emissions, and you equip the wet seal fluid degassing s ys tem with a cover that meet the requirements of section D.1(a) that is connected through a closed vent s ys tem that mee ts the requirements of section D.1(b) and is routed to a control device that meets the requirements of section E.1. As an alternative to routing the closed vent sy stem to a control device, you may route the closed vent s ys tem to a process. (3) You conduct an initial performance test as required in section F within 180 day s after the effective date specified by your regulatory

authority . (4) You conduct the initial cover and closed vent sy stem inspections required in section D.2 within 180 day s after the eff ective date specified by

your regulatory

authority . (5) You submit the initial annual report for your centrifugal compressor as required in section C.6(b)(1). (6) You maintain the records as specified in section C.6(a)(1) (b) Reciprocating c ompressors . You have achieved initial compliance with the VOC emission control requirements for each reciprocating compressor if you have complied with paragraphs (b)(1) through (4) of this section. (1) If complying with section C.3(a)(1) and (2), yo u must continuously m onitored the number of hours of operation or tracked the number of months since the last rod packing replacement , beginning on the compliance date specified by your regulatory

authority . (2) If complying with section C.3(a)(3), you must operate the rod pac king emissions collection sy stem under negative pressure and route emissions to a process through a closed vent sy stem that meets the requirements of section D.1(b) by the compliance date specified by your regulatory

authority .***E.O. 12866 R eview

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Appendix : C - 5 (3) You must submit the init ial annual report for your reciprocating compressor as required in section C.6(b)(2). (4) You maintain the records as specified in section C.6(a)(2). 

### C.5 **Continuous Compliance Demonstration Requirements** You have demonstrated continuous compliance for each centrifugal compressor by complying with the requirements of paragraph (a), and for each reciprocating compressor by complying with the requirements of paragraph (b). (a) Centrifugal c ompressors . For each centrifugal compressor subject to VOC emission reduction requirements, you must demonstrate continuous compliance according to paragraphs (a)(1) through (3) of this section. (1) You must reduce VOC emissions from the wet seal fluid degassing s ys tem by 95.0 percent or greater. (2) For each control devic e used to reduce emissions, you must demonstrate continuous compliance with the performance requirements of section C.2(a) using the procedures specified in paragraphs (a)(2)(i) through (vii) of this section. If you use a condenser as the control device to achieve the requirements specified in section C.2(a), you must demonstrate compliance according to paragraph (a)(2)(viii) of this section. You may switch between compliance with paragraphs (a)(2)(i) through (vii) of this section and compliance with paragr aph (a)(2)(viii) of this section only

after at least 1 year of operation in compliance with the selected approach. You must provide notification of such a change in the compliance method in the next annual report, as required in section C.6(b), following the change. (i) You must operate below (or above) the site specific maximum (or minimum) parameter value established according to the requirements of section E.2(f)(1). (ii) You must calculate the daily average of the applicable monitored parameter in accordance with section E.2(e) except that the inlet gas flow rate to the control device must not be averaged.***E.O. 12866 R eview

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Appendix : C - 6 (iii) Compliance with the operating parameter limit is achieved when the daily average of the monitoring parameter value calculated under paragraph (a)(2)(ii) of this section is either equal to or greater than the minimum monitoring value or equal to or less than the maximum monitoring value established under paragraph (a)(2)(i) of this section. When performance testing of a combustion control device is conducted by the device manufacturer as specified in section F(d), compliance with the operating parameter limit is achieved when the criteria in section F(e) are met. (iv) You must operate the continuous monitoring sy stem required in section E.2(a) at al l times the source is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring s ys tem malfunctions, and required monitoring sy stem quality assurance or quality control activities (including, as applicable, s ys tem accuracy audits and required zero and span adjustments). A monitoring s ys tem malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring s ys tem to provide valid data. Monitoring s ys tem failures that are caused in part by poo r maintenance or careless operation are not malfunctions. You are required to complete monitoring s ys tem repairs in response to monitoring sy stem malfunctions and to return the monitoring sy stem to operation as expeditiously

as practicable. (v) You may

not use data recorded during monitoring s ys tem malfunctions, repairs associated with monitoring s ys tem malfunctions, or required monitoring sy stem quality assurance or control activities in calculations used to report emissions or operating levels. You must u se all the data collected during all other required data collection periods to assess the operation of the control device and associated control sy stem. (vi) Failure to collect required data is a deviation of the monitoring requirements, except for periods of monitoring sy stem malfunctions, repairs associated with monitoring s ys tem malfunctions, and required quality monitoring s ys tem quality assurance or quality

control activities (including, as applicable, sy stem accuracy audits and required zero and span adjustments).***E.O. 12866 R eview

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Appendix : C - 7 (vii) If you use a combustion control device to meet the requirements of section C.2(a) and you demonstrate compliance using the test procedures specified in section F(b), you must comply with paragraphs (a)(2)(vii)(A) through (D) of this sec tion. (A) A pilot flame must be present at all times of operation. (B) Devices must be operated with no visible emissions, except for periods not to exceed a to tal of one minute during any 15 - minute period. A visible emissions test using section 11 of Meth od 22, 40 CFR part 60, appendix A, must be performed at least once every calendar month, separated b y at least 15 days between each test. The observation period shall be 15 minutes. (C) Devices failing the visible emissions test must follow manufacturer's repair instructions, if available, or best combustion engineering practice as outlined in the unit inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair and maintenance activities for each unit must be recorded in a maintenance and repair log and must be available for inspection. (D) Following return to operation from maintenance or repair activity , each device must pass a Method 22, 40 CFR part 60, appendix A, visual observation as described in paragraph (a)(2) (vii)(B) of this section. (viii) If you use a condenser as the control device to achieve the percent reduction performance requirements specified in section C.2(a)(1), you must demonstrate compliance using the procedures in paragraphs (a)(2)(viii)(A) through (E) of this section. (A) You must establish a site - specific condenser performance curve according to section E.2(f)(2). (B) You must calculate the daily average condenser outlet temperature in accordance with section E.2(e). (C) You must determine the c ondenser efficiency for the current operating day using the daily average condenser outlet temperature calculated under paragraph (a)(2)(viii)(B) of this***E.O. 12866 R eview

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Appendix : C - 8 section and the condenser performance curve established under paragraph (a)(2)(viii)(A) of this sectio n. (D) You must calculate the 365 - day rolling average TOC emission reduction, as appropriate, from the condenser efficiencies as determined in paragraph (a)(2)(viii)(C) of this section. ( 1 ) If you have less than 120 days of data for determining average TOC emission reduction, you must calculate the average TOC emission reduction for the first 120 days of operation. You have demonstrated compliance with the overall 95.0 percent reduction requirement if the 120 - day average TOC emission reduction is equal to or greater than 95.0 percent. ( 2 ) After 120 day s and no more than 364 day s of operation, you must calculate the average TOC emission reduction as the TOC emission reduction averaged over the number of day s of operation where you have data. You have demonstrated compliance with the overall 95.0 percent reduction requirement, if the average TOC emission reduction is equal to or greater than 95.0 percent. (E) If you have data for 365 days or more of operation, you have demonstrated compliance with the TOC emission reduction if the rolling 365 - day average TOC emission reduction calculated in paragraph (a)(2)(viii)(D) of this section is equal to or greater than 95.0 percent. (3) You must submit the annual report required b y section C.6(b)(1) and maintain the records as specified in section C.6(a)(1). (b) Reciprocating c ompressors . For each reciprocating compressor subject to VOC emission reduction requirements, you must demonstrate continuous compli ance according to paragraphs (b)(1) through (4 ) of this section. (1) You must continuously monitor the number of hours of operation for each reciprocating compressor or track the number of months or the date of the most recent***E.O. 12866 R eview

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Appendix : C - 9 reciprocating compressor rod packing replacement, whichever is later , beginning on the compliance date . (2) You must submit the annual report as required in section C.6(b)(2) and maintain records as required in section C.6(a)(2). (3) You must replace the reciprocating compressor rod p acking before the total number of hours of operation reaches 26,000 hours or the number of months since the most recent rod packing replacement reaches 36 months. (4) If you comply

with this rule by

collecting and routing VOC emissions from the rod packin g using a rod packing emissions collection sy stem which operates under negative pressure as required b y s ection C.3(a)(3), you must operate the rod packing emissions collection system under negative pressure and route emissions to a process through a close d vent sy stem that meets the requirements of section D.1(b). 

### C.6 **Recordkeeping and Reporting Requirements** (a) Recordkeeping requirements . (1) Centrif

ugal c ompressors . For each centrifugal compressor, the information specified in paragraphs (a)(1)(i) and (ii) of this section, and, if required to compl y with section C.2(a), the records specified in paragraphs (a)(1)(iii) through (viii) of this section. (i) An identificati on of each existing centrifugal compressor using a wet seal sy stem and each centrifugal compressor constructed, modified or reconstructed during the reporting period. (ii) Records of deviations where the centrifugal compressor was not operated in complianc e with requirements specified in section C.2. (iii) Records of each closed vent s ys tem inspection required under section D.2(a) and (b). (iv) A record of each cover inspection required under section D.2(c).***E.O. 12866 R eview

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Appendix : C - 10 (v) If you are subject to the bypass requirements of section D.2(d), a record of each inspection or a record each time the key is checked out or a record of each time the alarm is sounded. (vi) If you are subject to the closed vent s ys tem no detectable emissions requirements of section D.2(a) and (b), a record of the monitoring in accordance with section D.2(e). (vii) For each centrifugal compressor, records of the schedule for carbon replacement (as determined b y the design anal ys is requirements of section F(c)(2) or (3)) and records of each carbon repla cement as specified in section E.1(c)(1). (viii) For each centrifugal compressor subject to the control device requirements of section X.E.1, records of minimum and maximum operating parameter values, continuous parameter monitoring s ys tem data, calculated averages of continuous parameter monitoring sy stem data, results of all compliance calculations, and results of all inspections. (2) Reciprocating c ompressors . For each reciprocating compressor VOC emissions source, you must maintain the records in paragraphs (a)(2)(i) through (iii) of this section. (i) Records of the cumulative number of hours of operation or number of months since the previous replacement of the recip rocating compressor rod packing, or date of installation of a rod packing emissions coll ection sy stem and closed vent sy stem as specified in section C.3(a)(3).. (ii) Records of the date and time of each reciprocating compressor rod packing replacement. (iii) Records of deviations in cases where the reciprocating compressor was not operated in compliance with the requirements specified in section C.3. (b) Reporting requirements . (1) Centrifugal c ompressors . For each centrifugal compressor, you must submit annual reports containing the information specified in paragraphs (b)(1)(i) through (iii ) of this section.***E.O. 12866 R eview

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Appendix : C - 11 (i) An identification of each existing centrifugal compressor using a wet seal sy stem and each centrifugal compressor constructed, modified or reconstructed during the reporting period. (ii) Records of deviations specified in paragraph ( a)(1)(ii) of this section that occurred during the reporting period. (iii) If required to comply with section C.2(a), the records specified in paragraphs (a)(1)(iii) through (viii) of this section. (2) Reciprocating c ompressors . For each reciprocating comp ressor, you must submit annual reports containing the information specified in paragraphs (b)(2)(i) and (ii) of this section. (i) The cumulative number of hours of operation or the number of months since the compliance date , or since the previous reciprocating compressor rod packing replacement , whichever is later . (ii) Records of deviations specified in paragraph (a)(2)(iii) of this section that occurred during the reporting period. 

### C.7 **Definitions** Centrifugal compressor means any machin e for raising the pressure of a natural gas by drawing in low pressure natural gas and discharging significantl y higher pressure natural gas b y means of mechanical rotating vanes or impellers. Screw, sliding vane, and liquid ring compressors are not centri fugal compressors for the purposes of this rule. Compressor station means any permanent combination of one or more compressors that move natural gas at increased pressure from fields, in transmission pipelines, or into storage. Reciprocating compressor means a piece of equipment that increases the pressure of a process gas b y positive displacement, emplo yi ng linear movement of the driveshaft.***E.O. 12866 R eview

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Appendix : C - 12 Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around the rec iprocating compressor piston rod to create a seal limiting the amount of compressed natural gas that escapes to the atmosphere. Routed to a process or route to a process means the emissions are conveyed via a closed vent sy stem to any enclosed portion of a process where the emissions are predominantly recycled and/or consumed in the same manner as a material that fulfills the same function in the process and/or transformed b y chemical reaction into materials that are not regulated materials and/or incorporated into a product; and/or recovered. Salable quality gas means natural gas that meets the flow line or collection sy stem operator specifications, regardless of whether such gas is sold.***E.O. 12866 Review

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Appendix : D - 1 

### D **Cover and Closed Vent System Requirements D.1**  **What Are M y**  **Cover and Closed Vent S ystem**  **R equirements?**  You must meet the applicable requirements of this section for each cover and closed vent sy stem where VOC emissions are routed to a control device or to a process. (a) Cover requirements . (1) The cover and all openings on the cover ( e.g ., access hatches, sampling ports, pressure relief valves and gauge wells) shall form a continuous impermeable barrier over th e entire surface area of the liquid in the storage vessel or wet seal fluid degassing sy stem. (2) Each cover opening shall be secured in a closed, sealed position (e.g., covered b y a gasketed lid or cap) whenever material is in the unit on which the cover is installed except during those times when it is necessary to use an opening as follows: (i) To add material to, or remove material from the unit (this includes openings necessary to equalize or balance the internal pressure of the unit following changes in the level of the material in the unit); (ii) To inspect or sample the material in the unit; (iii) To inspect, maintain, repair, or replace equipment located inside the unit; or (iv) To vent liquids, gases, or fumes from the unit through a closed - vent sy stem, designed and operated in accordance with the requirements of paragraph (b)(1) of this section to a control device or to a process. (3) Additional cover requirement for storage vessels . Each storage vessel thief hatch shall be equipped, maintained and operated with a weighted mechanism or equivalent, to ensure that the lid remains properl y s eated. You must select gasket material for the hatch based on composition of the fluid in the storage vessel and weather conditions.***E.O. 12866 R eview

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Appendi x : D - 2 (b) Closed vent system requirem ents . For closed vent sy stem requirements using a control device or routing emissions to a process, you must comply with the following: (1) You must design the closed vent s ys tem to route all gases, vapors, and fumes emitted from the VOC emissions source to a control device that meets the requirements specified in section E.1(a) and (c), or to a process. (2) You must design and operate a closed vent sy stem with no detectable emissions, as determined using olfactory , visual and auditory inspections. Each cl osed vent sy stem that routes emissions to a process must be operational 95 percent of the ye ar or greater. (3) You must meet the requirements specified in paragraph (b)(3)(i) of this section if the closed vent s ys tem contains one or more b ypass devices that could be used to divert all or a portion of the gases, vapors, or fumes from entering the control device or to a process. (i) Except as provided in paragraph (b)(3)(ii) of this section, you must comply with either paragraph (b)(3)(i)(

A ) or ( B ) of this se ction for each by pass device. (A) You must properly

install, calibrate, maintain, and operate a flow indicator at the inlet to the by

pass device that could divert the stream away from the control device or process to the atmosphere. Set the flow indicator to trigger an audible alarm and initiate notification via remote alarm to the nearest field office, when the by pass device is open such that the stream is being, or could be, diverted away from the control device or process to the atmosphere. (B) You must secure the by pass device valve installed at the inlet to the by pass device in the non - diverting position using a car- seal or a lock - and - key typ e configuration. (ii) L ow leg drains, high point bleeds, anal yz er vents, open - ended valves or lines, and safety devices are not subject to the requirements of paragraph (b)(3)(i) of this section.***E.O. 12866 R eview

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Appendi x : D - 3 

### D.2 **What Are My Initial and Continuous Cover and Closed Vent System I**  **nsp ection and Monitoring R** **equirements?** Except as provided in paragraphs (e)(11) and (12) of this sectio n, you must inspect each closed vent s ys tem according to the procedures and schedule specified in paragraphs (a) and (b) of this section, inspect each cover according to the procedures and schedule specified in paragraph (c) of this section, and inspect ea ch b yp ass device according to the procedures of paragraph (d) of this section. (a) For each closed vent sy stem joint, seam, or other connection that is permanently or semi - permanentl y sealed (e.g., a welded joint between two sections of hard piping or a bo lted and gasketed ducting flange), you must meet the requirements specified in paragraphs (a)(1) and (2) of this section. (1) Conduct an initial inspection according to the test methods and procedures specified in paragraph (e) of this section to demonstrate that the closed vent s ys tem operates with no detectable emissions. You must maintain records of the inspection results. (2) Conduct annual visual inspections for defects that could result in air emissions. Defects include, but are not limited to, visibl e cracks, holes, or gaps in piping; loose connections; liquid leaks; or broken or missing caps or other closure devices. You must monitor a component or connection using the test methods and procedures in paragraph (b) of this section to demonstrate that i t operates with no detectable emissions following any time the component is repaired or replaced or the connection is unsealed. You must maintain records of the inspection results. (b) For closed vent s ys tem components other than those specified in paragra ph (a) of this section, you must meet the requirements of paragraphs (b)(1) through (3) of this section. (1) Conduct an initial inspection according to the test methods and procedures specified in paragraph (e) of this section to demonstrate that the close d vent s ys tem operates with no detectable emissions by

the date specified by

your regulatory

authority . You must maintain records of the inspection results.***E.O. 12866 R eview

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Appendi x : D - 4 (2) Conduct annual inspections according to the test methods and procedures specified in paragraph (e) of this section to demonstrate that the components or connections operate with no detectable emissions. You must maintain records of the inspection results. (3) Conduct annual visual inspections for defects that could result in air emissions. Defects i nclude, but are not limited to, visible cracks, holes, or gaps in ductwork; loose connections; liquid leaks; or broken or missing caps or other closure devices. You must maintain records of the inspection results. (c) For each cover, you must meet the requirements in paragraphs (c)(1) and (2) of this section. (1) Conduct visual inspections for defects that could result in air emissions. Defects include, but are not limited to, visible cracks, holes, or gaps in the cover, or between the cover and the separator wall; broken, cracked, or otherwise damaged seals or gaskets on closure devices; and broken or missing hatches, access covers, caps, or other closure devices. In the case where the storage vessel is buried partially or entirely

underground, you must inspect only those portions of the cover that extend to or above the ground surface, and those connections that are on such portions of the cover (e.g., fill ports, access hatches, gauge wells, etc.) and can be opened to the atmosphere. (2) You must in itially

conduct the inspections specified in paragraph (c)(1) of this section following the installation of the cover. Thereafter, you must perform the inspection at least once every calendar year, except as provided in paragraphs (e)(11) and (12) of this section. You must maintain records of the inspection results. (d) For each b ypass device, except as provided for in section D.1, you must meet the requirements of paragraphs (d)(1) or (2) of this section. (1) Set the flow indicator to take a reading at lea st once every 15 minutes at the inlet to the by pass device that could divert the steam away from the control device to the atmosphere.***E.O. 12866 R eview

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Appendi x : D - 5 (2) If the b yp ass device valve installed at the inlet to the by pass device is secured in the non - diverting position using a car - seal or a lock - and - key ty pe configuration, visually inspect the seal or closure mechanism at least once every month to verify

that the valve is maintained in the non - diverting position and the vent stream is not diverted through the b ypass device. Y ou must maintain records of the inspections. (e) No detectable emissions test methods and procedures. If you are required to conduct an inspection of a closed vent sy stem or cover as specified in paragraphs (a), (b), or (c) of this section, you must meet the requirements of paragraphs (e)(1) through (13) of this section. (1) You must conduct the no detectable emissions test procedure in accordance with Method 21, 40 CFR part 60, appendix A - 7. (2) The detection instrument must meet the performance criteria o f Method 21, 40 CFR part 60, appendix A - 7, except that the instrument response factor criteria in section 3.1.2(a) of Method 21 must be for the average composition of the fluid and not for each individual organic compound in the stream. (3) You must calibrate the detection instrument before use on each day of its use by

the procedures specified in Method 21, 40 CFR part 60, appendix A - 7. (4) Calibration gases must be as specified in paragraphs (e)(4)(i) and (ii) of this section. (i) Zero air (less than 10 p arts per million by volume hydrocarbon in air). (ii) A mixture of methane in air at a concentration less than 10,000 parts per million by volume. (5) You may

choose to adjust or not adjust the detection instrument readings to account for the background org anic concentration level. If you choose to adjust the instrument readings for the background level, you must determine the background level value according to the procedures in Method 21, 40 CFR part 60, appendix A - 7.***E.O. 12866 R eview

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Appendi x : D - 6 (6) Your detection instrument must mee t the performance criteria specified in paragraphs (e)(6)(i) and (ii) of this section. (i) Ex cept as provided in paragraph (e )(6)(ii) of this section, the detection instrument must meet the performance criteria of Method 21, 40 CFR part 60, appendix A - 7, e xcept the instrument response factor criteria in section 3.1.2(a) of Method 21 must be for the average composition of the process fluid, not each individual volatile organic compound in the stream. For process streams that contain nitrogen, air, or other inerts that are not volatile organic compounds, you must calculate the average stream response factor on an inert - free basis. (ii) If no instrument is available that will meet the performance criteria specified in paragraph (e)(6)(i) of this section, you may adjust the instrument readings by multiplying by

the average response factor of the process fluid, calculated on an inert - free basis, as described in paragraph (e)(6)(i) of this section. (7) You must determine if a potential leak interface operates with no detectable emissions using the applicable procedure specified in paragraph (e)(7)(i) or (ii) of this section. (i) If you choose not to adjust the detection instrument readings for the background organic concentration level, then you must directly compare the maximum organic concentration value measured b y the detection instrument to the applicable value for the potential leak interface as specified in paragraph (e)(8) of this section. (ii) If you choose to adjust the detection instrument readings for the background organic concentration level, you must compare the value of the arithmetic difference between the maximum organic concentration value measured by the instrument and the background organic concentration value as determined in paragraph (e)(5) of this section with the applicable value for the potential leak interface as specified in paragraph (e)(8) of this section. (8) A potential leak interface is determined to operate with no detectable organic emissions if the organic concentration value determ ined in paragraph (e)(7) of this section is less than 500 parts per million by volume.***E.O. 12866 R eview

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Appendi x : D - 7 (9) Repairs. In the event that a leak or defect is detected, you must repair the leak or defect as soon as practicable according to the requirements of paragraphs (e)(9) (i) and (ii) of this section, except as provided in paragraph (e)(10) of this section. (i) A first attempt at repair must be made no later than 5 calendar day s after the leak is detected. (ii) Repair must be completed no later than 15 calendar day s after the leak is detected. (10) Delay of repair. Delay of repair of a closed vent sy stem or cover for which leaks or defects have been detected is allowed if the repair is technically infeasible without a shutdown, or if you determine that emissions resulting from immediate repair would be greater than the fugitive emissions likely

to result from delay

of repair. You must complete repair of such equipment by

the end of the next shutdown. (11) Unsafe to inspect requirements. You may designate any

parts of the clos ed vent sy stem or cover as unsafe to inspect if the requirements in paragraphs (e)(11)(i) and (ii) of this section are met. Unsafe to inspect parts are exempt from the inspection requirements of paragraphs (a) through (c) of this section. (i) You determine that the equipment is unsafe to inspect because inspecting personnel would be exposed to an imminent or potential danger as a consequence of complying with paragraphs (a), (b), or (c) of this section. (ii) You have a written plan that requires inspection of the equipment as frequently as practicable during safe - to - inspect times. (12) Difficult to inspect requirements. You may designate any

parts of the closed vent sy stem or cover as difficult to inspect, if the requirements in paragraphs (e)(12)(i) and (ii ) of this section are met. Difficult to inspect parts are exempt from the inspection requirements of paragraphs (a) through (c) of this section. (i) You determine that the equipment cannot be inspected without elevating the inspecting personnel more than 2 meters above a support surface.***E.O. 12866 R eview

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Appendi x : D - 8 (ii) You have a written plan that requires inspection of the equipment at least once every 5 years.(13) Records. Records shall be maintained as specified in this section and in sections that reference this section.***E.O. 12866 Review

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Appendix : E - 1 

### E **VOC Emission Control Device Requirements**  **E.1 Initial Control Device Compliance Requirements**  You must meet the applicable requirements of this section for each control device used to comply with VOC emission reduction requirements by the compliance date specified by your regulatory

authority . (a) Each control device used to meet the VOC emission reduction requirements must be installed according to paragraphs (a)(1) through (3) of this section. As an alternative, you may install a control device model tested under section F(d), which meets the criteria in section F(d)(11) and section F(e). (1) Each combustion device ( e.g. , thermal vapor incinerator, catal yt ic vapor incinerator, boiler, or process heater) must be designed and operated in accordance with one of the performance requirements specified in paragraphs (a)(1)(i) through (iv) of this section. (i) You must reduce the mass content of VOC in the gas es vented to the device by 95 percent b y weight or greater as determined in accordance with the requirements of section F (b) . (ii) You must reduce the concentration of TOC in the exhaust gases at the outlet to the device to a level equal to or less than 6 00 parts per million by volume on a dry

basis corrected to 3 percent ox ygen as determined in accordance with the requirements of section F (b) . (iii) You must operate at a minimum temperature of 760°C for a control device that can demonstrate a uniform co mbustion zone temperature during the performance test conducted under section F (b) . (iv) If a boiler or process heater is used as the control device, then you must introduce the vent stream into the flame zone of the boiler or process heater. (2) Each vapo r recovery

device ( e.g. , carbon adsorption sy stem or condenser) or other non - destructive control device must be designed and operated to reduce the mass content of***E.O. 12866 R eview

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Appendix : E - 2 VOC in the ga ses vented to the device b y 95 percent by weight or greater as determined in ac cordance with the requirements of section F. As an alternative to the performance testing requirements, you may demonstrate initial compliance b y conducting a design analy sis for vapor recovery devices according to the requirements of section F(c). (3) You must design and operate a flare in accordance with the requirements of section F. (b) You must operate each control device installed to control VOC emissions from your emissions source in accordance with the requirements specified in paragraphs (b)(1) and (2) of this section. (1) You must operate each control device used to comply with this rule at all times when gases, vapors, and fumes are vented from your VOC emissions source through the closed vent sy stem to the control device. You may vent more than o ne source to a control device used to comply with this rule. (2) For each control device monitored in accordance with the requirements of section E.2(a) through (g), you must demonstrate continuous compliance according to the requirements of section A.4(c) for storage vessels, section C.5(a)(2) for centrifugal compressors, section H.4 for pneumatic pumps, and as applicable. (c) For each carbon adsorption system used as a control device to meet the requirements of paragraph (a)(2) of this section, you must manage the carbon in accordance with the requirements specified in paragraphs (c)(1) or (2) of this section. (1) Following the compliance date established b y yo ur regulatory authority for the source using the control device, you must replace all carbon in the control device with fresh carbon on a regular, predetermined time interval that is no longer than the carbon service life established according to section F(c)(2) or (3) or according to the design required in paragraph (a)(2) of this section, for the c arbon adsorption sy stem. You must maintain records identifying the schedule for replacement and records of each carbon replacement.***E.O. 12866 R eview

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Appendix : E - 3 (2) You must either regenerate, reactivate, or burn the spent carbon removed from the carbon adsorption sy stem in one of the units specified in paragraphs (c)(2)(i) through (vii) of this section. (i) Regenerate or reactivate the spent carbon in a thermal treatment unit for which you have been issued a final permit under 40 CFR part 270 that implements the requirements of 40 CFR part 264, subpart X. (ii) Regenerate or reactivate the spent carbon in a thermal treatment unit equipped with and operating air 95 percent s in accordance with this section. (iii) Regenerate or reactivate the spent carbon in a thermal treatment unit equipp ed with and operating organic air 95 percent s in accordance with an emissions standard for VOC under this rule. (iv) Burn the spent carbon in a hazardous waste incinerator for which the owner or operator has been issued a final permit under 40 CFR part 270 that implements the requirements of 40 CFR part 264, subpart O. (v) Burn the spent carbon in a hazardous waste incinerator which you have designed and operated in accordance with the requirements of 40 CFR part 265, subpart O. (vi) Burn the spent carbon i n a boiler or industrial furnace for which you have been issued a final permit under 40 CFR part 270 that implements the requirements of 40 CFR part 266, subpart H. (vii) Burn the spent carbon in a boiler or industrial furnace that you have designed and op erated in accordance with the interim status requirements of 40 CFR part 266, subpart H. 

### E.2 **Continuous Control Device Monitoring Requirements** You must meet the applicable requirements of this section to demonstrate continuous compliance for each control device used to meet VOC emission control requirements.***E.O. 12866 R eview

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Appendix : E - 4 (a) For each control device used to compl y with the VOC emission reduction requirements, you must install and operate a continuous parameter monitoring s ys tem for each control device as specified in paragraphs (c) through (h) of this section, except as provided for in paragraph (b) of this section. I f you install and operate a flare in accordance with section E.1(a)(3), you are exempt from the requirements of paragraphs (e) and (f) of this section. (b) You are exempt from the monitoring requirements specified in paragraphs (c) through (f) of this section for the control devices listed in paragraphs (b)(1) and (2) of this section. (1) A boiler or process heater in which all vent streams are introduced wi th the primary fuel, or used as the primary fuel. (2) A boiler or process heater with a design heat input capacity equal to or greater than 44 megawatts. (c) If you are required to install a continuous parameter monitoring s ys tem, you must meet the specifi cations and requirements in paragraphs (c)(1) through (4) of this section. (1) Each continuous parameter monitoring s ys tem must measure data values at least once every hour and record the parameters in paragraphs (c)(1)(i) or (ii) of this section. (i) Each measured data value. (ii) Each block average value for each 1 - hour period or shorter periods calculated from all measured data values during each period. If values are measured more frequently than once per minute, a single value for each minute may be us ed to calculate the hourly (or shorter period) block average instead of all measured values. (2) You must prepare a site - specific monitoring plan that addresses the monitoring sy stem design, data collection, and the quality assurance and quality control el ements outlined in paragraphs (c)(2)(i) through (v) of this section. You must install, calibrate, operate, and maintain each continuous parameter monitoring s ys tem in accordance with the procedures in your approved site - specific monitoring plan.***E.O. 12866 R eview

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Appendix : E - 5 (i) The pe rformance criteria and design specifications for the monitoring s ystem equipment, including the sample interface, detector signal anal yz er, and data acquisition and calculations. (ii) Sampling interface (e.g., thermocouple) location such that the monitoring s ys tem will provide representative measurements. (iii) Equipment performance checks, s ys tem accuracy audits, or other audit procedures. (iv) On - going operation and maintenance procedures in accordance with provisions in 40 CFR 60.13(b). (v) Ongoing reporting and recordkeeping procedures in accordance with provisions in 40 CFR 60.7(c), (d), and (f). (3) You must conduct the continuous parameter monitoring s ys tem equipment performance checks, s ys tem accuracy audits, or other audit procedures specified in the site specific monitoring plan at least once every 12 months. (4) You must conduct a performance evaluation of each continuous parameter monitoring sy stem in accordance with the site - specific monitoring plan. (d) You must install, calibrate, operate, an d maintain a device equipped with a continuous recorder to measure the values of operating parameters appropriate for the control device as specified in either paragraph (d)(1), (2), or (3) of this section. (1) A continuous monitoring s ys tem that measures the operating parameters in paragraphs (d)(1)(i) through (viii) of this section, as applicable. (i) For a thermal vapor incinerator that demonstrates during the performance test conducted under section X.F that combustion zone temperature is an accurate indicator of performance, a temperature monitoring device equipped with a continuous recorder. The monitoring device must have a minimum accuracy of ±1 percent of the temperature being***E.O. 12866 R eview

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Appendix : E - 6 monitored in °C, or ±2.5°C, whichever value is greater. You must install the temperature sensor at a location representative of the combustion zone temperature. (ii) For a catal yt ic vapor incinerator, a temperature monitoring device equipped with a continuous recorder. The device must be capable of monitoring temperature at two locations and have a minimum accuracy of ±1 percent of the temperature being monitored in °C, or ±2.5°C, whichever value is greater. You must install one temperature sensor in the vent stream at the nearest feasible point to the catal ys t bed inlet, and yo u must install a second temperature sensor in the vent stream at the nearest feasible point to the catal ys t bed outlet. (iii) For a flare, a heat sensing monitoring device equipped with a continuous recorder that indicates the continuous ignition of the pi lot flame. (iv) For a boiler or process heater, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device must have a minimum accuracy of ±1 percent of the temperature being monitored in °C, or ±2.5°C, whichever value is greater. You must install the temperature sensor at a location representative of the combustion zone temperature. (v) For a condenser, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device must hav e a minimum accuracy of ±1 percent of the temperature being monitored in °C, or ±2.8°C, whichever value is greater. You must install the temperature sensor at a location in the exhaust vent stream from the condenser. (vi) For a regenerative - ty pe carbon ads orption s ys tem, a continuous monitoring s ys tem that meets the specifications in paragraphs (d)(1)(vi)(A) and (B) of this section. (A) The continuous parameter monitoring s ys tem must measure and record the average total regeneration stream mass flow or volumetric flow during each carbon bed regeneration cycle. The flow sensor must have a measurement sensitivity of 5 percent of the flow rate or 10 cubic feet per minute, whichever is greater. You must check the mechanical connections for leakage at least every month, and you must perform a visual inspection at least every 3 months of all components of the flow continuous parameter monitoring sy stem for phy sical and operational***E.O. 12866 R eview

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Appendix : E - 7 integrity and all electrical connections for oxidation and galvanic corrosion if your flow continuous parameter monitoring s ys tem is not equipped with a redundant flow sensor; and (B) The continuous parameter monitoring s ys tem must measure and record the average carbon bed temperature for the duration of the carbon bed steaming cycle and m easure the actual carbon bed temperature after regeneration and within 15 minutes of completing the cooling cycle. The temperature monitoring device must have a minimum accuracy of ±1 percent of the temperature being monitored in °C, or ±2.5°C, whichever v alue is greater. (vii) For a non - regenerative - ty pe carbon adsorption sy stem, you must monitor the design carbon replacement interval established using a performance test performed as specified in section X.F(b). The design carbon replacement interval must be based on the total carbon working capacity

of the control device and source operating schedule. (viii) For a combustion control device whose model is tested under section X.F(d), a continuous monitoring system meeting the requirements of paragraphs (d)( 1)(viii)(A) and (B) of this section. (A) The continuous monitoring s ys tem must measure gas flow rate at the inlet to the control device. The monitoring instrument must have an accuracy of ±2 percent or better. The flow rate at the inlet to the combustion d evice must not exceed the maximum or minimum flow rate determined b y the manufacturer. (B) A monitoring device that continuously indicates the presence of the pilot flame while emissions are routed to the control device. (2) An organic monitoring device eq uipped with a continuous recorder that measures the concentration level of organic compounds in the exhaust vent stream from the control device. The monitor must meet the requirements of Performance Specification 8 or 9 of 40 CFR part 60, appendix B. You must install, calibrate, and maintain the monitor according to the manufacturer's specifications.***E.O. 12866 R eview

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Appendix : E - 8 (3) A continuous monitoring s ys tem that measures operating parameters other than those specified in paragraph (d)(1) or (2) of this section, upon approval of the regulatory authority . (e) You must calculate the daily average value for each monitored operating parameter for each operating day , using the data recorded b y the monitoring s ys tem, except for inlet gas flow rate. If the emissions unit operation is cont inuous, the operating day is a 24 - hour period. If the emissions unit operation is not continuous, the operating day is the total number of hours of control device operation per 24 - hour period. Valid data points must be available for 75 percent of the operating hours in an operating day to compute the daily

average. (f) For each operating parameter monitor installed in accordance with the requirements of paragraph (d) of this section, you must comply with paragraph (f)(1) of this section for all control devi ces. When condensers are installed, yo u must also comply with paragraph (f)(2) of this section. (1) You must establish a minimum operating parameter value or a maximum operating parameter value, as appropriate for the control device, to define the conditio ns at which the control device must be operated to continuousl y achieve the applicable performance requirements of section E.1(a). You must establish each minimum or maximum operating parameter value as specified in paragraphs (f)(1)(i) through (iii) of this section. (i) If you conduct performance tests in accordance with the requirements of section F(b) to demonstrate that the control device achieves the applicable performance requirements specified in section E.1(a), then you must establish the minimum op erating parameter value or the maximum operating parameter value based on values measured during the performance test and supplemented, as necessary , by a condenser design anal ys is or control device manufacturer recommendations or a combination of both. (i i) If you use a condenser design anal ys is in accordance with the requirements of section F(c) to demonstrate that the control device achieves the applicable performance requirements specified in section E.1(a), then you must establish the minimum operating parameter value or the maximum operating parameter value based on the condenser design analy sis and supplemented, as necessary , by the condenser manufacturer's recommendations.***E.O. 12866 R eview

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Appendix : E - 9 (iii) If you operate a control device where the performance test requirement w as met under section F(d) to demonstrate that the control device achieves the applicable performance requirements specified in section E.1(a), then your control device inlet gas flow rate must not exceed the maximum or minimum inlet gas flow rate determine d by the manufacturer. (2) If you use a condenser as specified in paragraph (d)(1)(v) of this section, you must establish a condenser performance curve showing the relationship between condenser outlet temperature and condenser control efficiency , accordin g to the requirements of paragraphs (f)(2)(i) and (ii) of this section. (i) If you conduct a performance test in accordance with the requirements of section F(b) to demonstrate that the condenser achieves the applicable performance requirements in section E.1(a), then the condenser performance curve must be based on values measured during the performance test and supplemented as necessary by control device design analy sis, or control device manufacturer's recommendations, or a combination or both. (ii) If you use a control device design anal ys is in accordance with the requirements of section F(c)(1) to demonstrate that the condenser achieves the applicable performance requirements specified in section E.1(a), then the condenser performance curve must be bas ed on the condenser design analy sis and supplemented, as necessary , by the control device manufacturer's recommendations. (g) A deviation for a given control device is determined to have occurred when the monitoring data or lack of monitoring data result in any one of the criteria specified in paragraphs (g)(1) through (6) of this section being met. If you monitor multiple operating parameters for the same control device during the same operating day and more than one of these operating parameters meets a d eviation criterion specified in paragraphs (g)(1) through (6) of this section, then a single excursion is determined to have occurred for the control device for that operating day . (1) A deviation occurs when the dail y average value of a monitored operatin g parameter is less than the minimum operating parameter limit (or, if applicable, greater than the maximum operating parameter limit) established in paragraph (f)(1) of this section.***E.O. 12866 R eview

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Appendix : E - 10 (2) If you meet section E.1(a)(2), a deviation occurs when the 365 - day average condenser efficiency calculated according to the requirements specified in section F(b) is less than 95 percent. (3) If you meet section E.1(a)(2) and you have less than 365 day s of data, a deviation occurs when the average condenser efficiency calc ulated according to the procedures specified in section F(b) is less than 90.0 percent. (4) A deviation occurs when the monitoring data are not available for at least 75 percent of the operating hours in a day . (5) If the closed vent s ys tem contains one or more by pass devices that could be used to divert all or a portion of the gases, vapors, or fumes from entering the control device, a deviation occurs when the requirements of paragraphs (g)(5)(i) and (ii) of this section are met. (i) For each b yp ass line subject to section D.1(b)(3) (i )(A), the flow indicator indicates that flow has been detected and that the stream has been diverted away from the control device to the atmosphere. (ii) For each b yp ass line subject to section D.1(b)(3) (i )(B), if the seal or closure mechanism has been broken, the b ypass line valve position has changed, the key for the lock and - key type lock has been checked out, or the car- seal has broken. (6) For a combustion control device whose model is tested under section F(d), a deviatio n occurs when the conditions of paragraphs (g)(6)(i) or (ii) are met. (i) The inlet gas flow rate exceeds the maximum established during the test conducted under section F(d). (ii) Failure of the monthly visible emissions test conducted under section F(e)( 3) occurs. (h) Each control device used to meet a VOC emission reduction requirement must be operated following the manufacturer's written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions.***E.O. 12866 R eview

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Appendix : E - 11 Records of the manufacturer's written operating instructions, procedures, and maintenance schedule must be available for inspection.***E.O. 12866 Review

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Appendix : F - 1 

### F **Performance Test Procedures** This section applies to the performance testing of control devices used to demonstrate compliance with your VOC emission control requirements. You must demonstrate that a control device achieves the performance requirements specified for your emissions source using the performance test methods and procedures specified in this section. For condensers, you may use a design anal ys is as specified in paragraph (c) of this section in lieu of complying with paragraph (b) of this section. In addition, this section contains the requirements for enclosed combustion device performance tests conducted b y the manufacturer, as relevant and allowed for compliance demonstration purposes. (a) Performance test exemptions. You are exempt from the requirements to conduct performance tests and design anal ys es if you use any of the control devices described in paragraphs (a)(1) through (7) of this section. (1) A flare that is designed and operated in accordance with 40 CFR 60.18(b) . You must conduct the compliance determination using Method 22, 40 CFR part 60, appendix A - 7, to determine visible emissions. (2) A boiler or process heater with a design heat input capacity of 44 megawatts or greater. (3) A boiler or process heater into which the vent stre am is introduced with the primary fuel or is used as the primary fuel. (4) A boiler or process heater burning hazardous waste for which you have either been issued a final permit under 40 CFR part 270 and comply with the requirements of 40 CFR part 266, subpart H; or you have certified compliance with the interim status requirements of 40 CFR part 266, subpart H. (5) A hazardous waste incinerator for which you have been issued a final permit under 40 CFR part 270 and comply with the requirements of 40 CFR p art 264, subpart O; or you have certified compliance with the interim status requirements of 40 CFR part 265, subpart O.***E.O. 12866 R eview

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Appendix : F - 2 (6) A performance test is waived in accordance with 40 CFR 60.8(b). (7) A control device whose model can be demonstrated to meet the performance requirements of section E.1(a) through a performance test conducted by the manufacturer, as specified in paragraph (d) of this section. (b) Test methods and procedures. You must use the test methods and procedures specified in paragraphs (b)(1) through (5) of this section, as applicable, for each performance test conducted to demonstrate that a control device meets the requirements of section E.1(a). You must conduct the initial and periodic performance tests according to the schedule specified in paragraph (b)(5) of this section. (1) You must use Method 1 or 1A, 40 CFR part 60, appendix A - 1, as appropriate, to select the sampling sites specified in paragraphs (b)(1)(i) and (ii) of this section. Any references to particulate mentioned in Methods 1 and 1A do not apply to this section. (i) Sampling sites must be located at the inlet of the first control device, and at the outlet of the final control device, to determine compliance with the control device percent reduction requirement specified in se ction E.1(a)(1)(i) or (a)(2). (ii) The sampling site must be located at the outlet of the combustion device to determine compliance with the enclosed combustion device TOC concentration limit specified in section E.1 (a)(1)(ii). (2) You must determine the g as volumetric flowrate using Method 2, 2A, 2C, or 2D, 40 CFR part 60, appendix A - 2, as appropriate. (3) To determine compliance with the control device percent reduction performance re quirement in section E.1 (a)(1)(i) or (a)(2), you must use Method 25A at 40 CFR part 60, appendix A - 7. You must use the procedures in paragraphs (b)(3)(i) through (iv) of this section to calculate percent reduction efficiency .***E.O. 12866 R eview

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Appendix : F - 3 (i) For each run, you must take either an integrated sample or a minimum of four grab samples per hour . I f grab sampling is used, then the samples must be taken at approximately equal intervals in time, such as 15 - minute intervals during the run. (ii) You must compute the mass rate of TOC (minus methane and ethane) using the equations and procedures specif ied in paragraphs (b)(3)(ii)(A) and (B) of this section. (A) You must use the following equations:

Where: E i , E o = Mass rate of TOC (minus methane and ethane) at the inlet and outlet of the control device, respectively , dry basis, kilogram per hour. K2 = Constant, 2.494 × 10 −6 (parts per million) (gram - mole per standard cubic meter) (kilogram/gram) (minute/hour), where standard temperature (gram - mole per standard cubic meter) is 20°C. C ij , C oj = Concentration of sample component j of the gas stream at the inlet and outlet of the control device, respectively , dry basis, parts per million by volume. M ij , M oj = Molecular weight of sample component j of the gas stream at the inlet and outlet of the control device, respectivel y, gram/gram - mole. Q i , Q o = Flowrate of gas stream at the inlet and outlet of the control device, respectivel y, dry standard cubic meter per minute. n = Number of components in sample. i n 1 j ij ij 2 i Q

M C K E 

        

# 



o n 1 j oj oj 2 o Q

M C K E 

        

# 

***E.O. 12866 R eview

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Appendix : F - 4 (B) When calculating the TOC mass rate, you must sum all organic compounds (minus methane and ethane) m easured b y Method 25A, 40 CFR part 60, appendix A - 7 using the equations in paragraph (b)(3)(ii)(A) of this section. (iii) You must calculate the percent reduction in TOC (minus methane and ethane) as follows:

Where: Rcd = Control efficiency of control device, percent. E i = Mass rate of TOC (minus methane and ethane) at the inlet to the control device as calculated under paragraph (b)(3)(ii) of this section, kilograms TOC per hour or kilograms HAP p er hour. E o = Mass rate of TOC (minus methane and ethane) at the outlet of the control device, as calculated under paragraph (b)(3)(ii) of this section, kilograms TOC per hour per hour. (iv) If the vent stream entering a boiler or process heater with a des ign capacity less than 44 megawatts is introduced with the combustion air or as a secondary fuel, you must determine the we ight - percent reduction of TOC (minus methane and ethane) across the device b y comparing the TOC (minus methane and ethane) in all combusted vent streams and primary and secondary fuels with the TOC (minus methane and ethane) exiting the device, respectivel y. (4) You must use Method 25A, 40 CFR part 60, appendix A - 7 to measure TOC (minus methane and ethane) to determine compliance with the enclosed combustion device total VOC concentration limit specified in section E.1(a)(1)(ii). You must calculate parts per million by volume concentration and correct to 3 percent oxygen, using the procedures in paragraphs (b)(4)(i) through (iii) of this section. 

### % 100 x E E E R i o

i cd 

###  ***E.O. 12866 R eview

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Appendix : F - 5 (i) For each run, you must take either an integrated sample or a minimum of four grab samples per hour. If grab sampling is used, then the samples must be taken at approximately equal intervals in time, such as 15 - minute intervals during the r un. (ii) You must calculate the TOC concentration for each run as follows:

Where: C TOC = Concentration of total organic compounds minus methane and ethane, dry basis, parts per million by

volume. C ji = Concentration of sample component j of sample I dry basis, parts per million by volume. n = Number of components in the sample. x = Number of samples in the sample run. (iii) You must correct the TOC concentration to 3 percent ox ygen as specified in paragraphs (b)(4)(iii)(A) and (B) of this section. (A) You must use the emission rate correc tion factor for excess air, integrated sampling and anal ys is procedures of Method 3A or 3B at 40 CFR part 60, appendix A, ASTM D6522 - 00 (Reapproved 2005), or ANSI/ASME PTC 19.10 - 1981, Part 10 (manual portion only) (incorporated b y reference as specified in §60.17) to determine the oxygen concentration. The samples must be taken during the same time that the samples are taken for determining TOC concentration. (B) You must correct the TOC concentration for percent ox ygen as follows:



#  

  

### 

      

 x 1 i n 1 j ji TOC 

### x

C C



      

  d 2 m c O

% 9 . 20 9 . 17 C C***E.O. 12866 R eview

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Appendix : F - 6 Where: C c = TOC concentration corrected to 3 percent oxygen, dry basis, parts per million by volume. C m = TOC concentration, dry basis, parts per million by volume. %O 2d = Concentration of ox ygen, dry basis, percent by volume. (5) You must conduct performance tests according to the schedule specified in paragraphs (b)(5)(i) and (ii) of this section. (i) You must conduct an initial performance test within 180 day s after the compliance date for your source. (ii) You must conduct periodic performance tests for all control devices required to conduct initial performance tests except as specified in paragraphs (b)(5)(ii)(A) and (B) of this section. You must conduct the first periodic performance test no later than 60 months a fter the initial performance test required in paragraph (b)(5)(i) of this section. You must conduct subsequent periodic performance tests at intervals no longer than 60 months following the previous periodic performance test or whenever you desire to estab lish a new operating limit. Combustion control devices meeting the criteria in either paragraph (b)(5)(ii)(A) or (B) of this section are not required to conduct periodic performance tests. (A) A control device whose model is tested under, and meets the cri teria of paragraph (d) of this section. (B) A combustion control device tested under paragraph (b) of this section that meets the outlet TOC performance level specified in section E.1(a)(1)(ii) and that establishes a correlation between firebox or combusti on chamber temperature and the TOC performance level. (c) Control device design analysis to meet the requirements of section E.1(a). (1) For a condenser, the design analy sis must include an analy sis of the vent stream composition, constituent concentration s, flowrate, relative humidity , and temperature, and must establish the design outlet organic compound concentration level, design average temperature of the***E.O. 12866 R eview

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Appendix : F - 7 condenser exhaust vent stream, and the design average temperatures of the coolant fluid at the con denser inlet and outlet. (2) For a regenerable carbon adsorption sy stem, the design anal ys is shall include the vent stream composition, constituent concentrations, flowrate, relative humidity, and temperature, and shall establish the design exhaust vent stream organic compound concentration level, adsorption cycle time, number and capacity of carbon beds, type and working capacity of activated carbon used for the carbon beds, design total regeneration stream flow over the period of each complete carbon bed regeneration cycle, design carbon bed temperature after regeneration, design carbon bed regeneration time, and design service life of the carbon. (3) For a non - regenerable carbon adsorption s ys tem, such as a carbon canister, the design anal ys is shall inclu de the vent stream composition, constituent concentrations, flowrate, relative humidity, and temperature, and shall establish the design exhaust vent stream organic compound concentration level, capacity of the carbon bed, type and working capacity of acti vated carbon used for the carbon bed, and design carbon replacement interval based on the total carbon working capacity

of the control device and source operating schedule. In addition, these sy stems will incorporate dual carbon canisters in case of emissi on breakthrough occurring in one canister. (4) If you and the regulated authority do not agree on a demonstration of control device performance using a design anal ys is, then you must perform a performance test in accordance with the requirements of paragra ph (b) of this section to resolve the disagreement. The regulatory authority may choose to have an authorized representative observe the performance test. (d) Performance testing for combustion control devices

—manufacturers' performance test. (1) This para graph applies to the performance testing of a combustion control device conducted b y the device manufacturer. The manufacturer must demonstrate that a specific model of control device achieves the performance requirements in paragraph (d)(11) of this secti on by conducting a performance test as specified in paragraphs (d)(2) through (10) of this section. You must submit a test report for each combustion control device in accordance with the requirements in paragraph (d)(12) of this section.***E.O. 12866 R eview

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Appendix : F - 8 (2) Performance testing must consist of three one - hour (or longer) test runs for each of the four firing rate settings specified in paragraphs (d)(2)(i) through (iv) of this section, making a total of 12 test runs per test. Propene (prop yl ene) gas must be used for the tes ting fuel. All fuel anal ys es must be performed by an independent third - party laboratory (not affiliated with the control device manufacturer or fuel supplier). (i) 90 - 100 percent of maximum design rate (fixed rate). (ii) 70 - 100 - 70 percent (ramp up, ramp do wn). Begin the test at 70 percent of the maximum design rate. During the first 5 minutes, incrementall y ramp the firing rate to 100 percent of the maximum design rate. Hold at 100 percent for 5 minutes. In the 10 - 15 minute time range, incrementall y ramp ba ck down to 70 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling. (iii) 30 - 70 - 30 percent (ramp up, ramp down). Begin the test at 30 percent of the maximum design rate. During the first 5 minutes, incrementall y ramp the firing rate to 70 percent of the maximum design rate. Hold at 70 percent for 5 minutes. In the 10 - 15 minute time range, incrementall y ramp back down to 30 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling. (iv) 0 - 30 - 0 percent (ramp up, ramp down). Begin the test at the minimum firing rate. During the first 5 minutes, incrementall y ramp the firing rate to 30 percent of the maximum design rate. Hold at 30 percent for 5 minutes. In the 10 - 15 minute time range, incrementally ramp back down to the minimum firing rate. Repeat three more times for a total of 60 minutes of sampling. (3) All models employing multiple enclosures must be tested simultaneously and with all burners operational. Results must be rep orted for each enclosure individually and for the average of the emissions from all interconnected combustion enclosures/chambers. Control device operating data must be collected continuously throughout the performance test using an electronic Data Acquisi tion Sy stem. A graphic presentation or strip chart of the control device operating data and emissions test data must be included in the test report in accordance with***E.O. 12866 R eview

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Appendix : F - 9 paragraph (d)(12) of this section. Inlet fuel meter data may be manually

recorded provide d that all inlet fuel data readings are included in the final report. (4) Inlet testing must be conducted as specified in paragraphs (d)(4)(i) and (ii) of this section. (i) The inlet gas flow metering s ys tem must be located in accordance with Method 2A, 40 CFR part 60, appendix A - 1, (or other approved procedure) to measure inlet gas flow rate at the control device inlet location. You must position the fitting for filling fuel sample containers a minimum of eight pipe diameters upstream of any inlet gas flow monitoring meter. (ii) Inlet flow rate must be determined using Method 2A, 40 CFR part 60, appendix A - 1. Record the start and stop reading for each 60 - minute THC test. Record the gas pressure and temperature at 5 - minute intervals throughout each 60 - minute test. (5) Inlet gas sampling must be conducted as specified in paragraphs (d)(5)(i) and (ii) of this section. (i) At the inlet gas sampling location, securely connect a Silonite - coated stainless steel evacuated canister fitted with a flow controller suffi cient to fill the canister over a 3 - hour period. Filling must be conducted as specified in paragraphs (d)(5)(i)(A) through (C) of this section. (A) Open the canister sampling valve at the beginning of each test run, and close the canister at the end of eac h test run. (B) Fill one canister across the three test runs such that one composite fuel sample exists for each test condition. (C) Label the canisters individually and record sample information on a chain of custody form. (ii) Anal yz e each inlet gas sample using the methods in paragraphs (d)(5)(ii)(A) through (C) of this section. You must include the results in the test report required by paragraph (d)(12) of this section.***E.O. 12866 R eview

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Appendix : F - 10 (A) Hydrocarbon compounds containing between one and five atoms of carbon plus benzene using ASTM D1945 - 03. (B) Hydrogen (H 2 ), carbon monoxide (CO), carbon dioxide (CO 2 ), nitrogen (N 2 ), ox ygen (O 2 ) using ASTM D1945 - 03. (C) Higher heating value using ASTM D3588 - 98 or ASTM D4891 - 89. (6) Outlet testing must be conducted in accordance wi th the criteria in paragraphs (d)(6)(i) through (v) of this section. (i) Sample and flow rate must be measured in accordance with paragraphs (d)(6)(i)(A) through (B) of this section. (A) The outlet sampling location must be a minimum of four equivalent sta ck diameters downstream from the highest peak flame or any other flow disturbance, and a minimum of one equivalent stack diameter upstream of the exit or any other flow disturbance. A minimum of two sample ports must be used. (B) Flow rate must be measured using Method 1, 40 CFR part 60, appendix A - 1 for determining flow measurement traverse point location, and Method 2, 40 CFR part 60, appendix A - 1 for measuring duct velocity . If low flow conditions are encountered ( i.e ., velocity pressure differentials less than 0.05 inches of water) during the performance test, a more sensitive manometer must be used to obtain an accurate flow profile. (ii) Molecular weight and excess air must be determined as specified in paragraph (d)( 7) of this section. (iii) Carbon monoxide must be determined as specified in paragraph (d)(8) of this section. (iv) THC must be determined as specified in paragraph (d)(9) of this section. (v) Visible emissions must be determined as specified in paragraph (d)(10) of this section.***E.O. 12866 R eview

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Appendix : F - 11 (7) Molecular weight and excess air determination must be performed as specified in paragraphs (d)(7)(i) through (iii) of this section. (i) An integrated bag sample must be collected during the Method 4, 40 CFR part 60, appendix A - 3, moisture test following the procedure specified in paragraphs (d)(7)(i)(A) and (B) of this section. Analyze the bag sample using a gas chromatograph - thermal conductivity detector (GC - TCD) analy sis meeting the criteria in paragraphs (d)(7)(i)(C) and (D) of this section. (A) Collect the integrated sample throughout the entire test, and collect representative volumes from each traverse location. (B) Purge the sampling line with stack gas before opening the valve and beginning to fill the bag. Clearl y label each bag and record sample information on a chain of custody form. (C) The bag contents must be vigorousl y mixed prior to the gas chromatograph anal ys is. (D) The GC - TCD calibration procedure in Method 3C, 40 CFR part 60, appendix A, must be modified by

usi ng EPA Alt - 045 as follows: For the initial calibration, triplicate injections of any single concentration must agree within 5 percent of their mean to be valid. The calibration response facto r for a single concentration re check must be within 10 percent of the original calibration response factor for that concentration. If this criterion is not met, repeat the initial calibration using at least three concentration levels. (ii) Calculate and report the molecular weight of oxygen, carbon dioxide, methane, and nitrogen in the integrated bag sample and include in the test report specified in paragraph (d)(12) of this section. Moisture must be determined using Method 4, 40 CFR part 60, appendix A - 3. Traverse both ports with the Method 4, 40 CFR part 60, appendix A - 3, sampling train during each test run. Ambient air must not be introduced into the Method 3C, 40 CFR part 60, appendix A - 2, integrated bag sample during the port change. (iii) Excess air must be determined using resultant data from the EPA Method 3C tes ts and EPA Method 3B, 40 CFR part 60, appendix A, equation 3B - 1.***E.O. 12866 R eview

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Appendix : F - 12 (8) Carbon monoxide must be determined using Method 10, 40 CFR part 60, appendix A. Run the test simultaneously with Method 25A, 40 CFR part 60, appendix A - 7 using the same sampling points. An instrument range of 0 - 10 parts per million by volume - dry

(ppmvd) is recommended. (9) Total h ydrocarbon determination must be performed as specified b y in paragraphs (d)(9)(i) through (vii) of this section. (i) Conduct THC sampling using Method 25A, 40 CF R part 60, appendix A - 7, except that the option for locating the probe in the center 10 percent of the stack is not allowed. The THC probe must be traversed to 16.7 percent, 50 percent, and 83.3 percent of the stack diameter during each test run. (ii) A valid test must consist of three Method 25A, 40 CFR part 60, appendix A - 7, tests, each no less than 60 minutes in duration. (iii) A 0 - 10 parts per million by volume - wet (ppmvw) (as propane) measurement range is preferred; as an alternative a 0 - 30 ppmvw (as carbon) measurement range may be used. (iv) Calibration gases must be propane in air and be certified through EPA Protocol 1

— “EPA Traceability

Protocol for Assay

and Certification of Gaseous Calibration Standards,” September 1997, as amended August 25, 199 9, EPA - 600/R - 97/121(or more recent if updated since 1999). (v) THC measurements must be reported in terms of ppmvw as propane. (vi) THC results must be corrected to 3 percent CO 2 , as measured b y Method 3C, 40 CFR part 60, appendix A - 2. You must use the fol lowing equation for this di luent concentration correction:          meas meas corr CO C C 2

3***E.O. 12866 R eview

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Appendix : F - 13 Where: C meas = The measured concentration of the pollutant. CO 2meas = The measured concentration of the CO 2 diluent. 3 = The corrected reference concentration of CO 2 diluent. C corr = The corrected concentration of the pollutant. (vii) Subtraction of methane or ethane from the THC data is not allowed in determining results. (10) Visible emissions must be determined using Method 22, 40 CFR part 60, appendix A. The test must be performed continuously during each test run. A digital color photograph of the exhaust point, taken from the position of the observer and annotated with date and time, must be taken once per test run and the 12 photos included in the test report specified in paragraph (d)(12) of this section. (11) Performance test criteria. (i) The control device model tested must meet the criteria in paragraphs (d)(11)(i)(A) through (D) of this section. These criteria must be reported in the test report required b y paragraph (d)(12) of this section. (A) Method 22, 40 CFR part 60, appendix A, results under paragraph (d)(10) of this section with no indication of visible emissions. (B) Average Method 25A, 40 CFR part 60, appendix A, result s under paragraph (d)(9) of this section equal to or less than 10.0 ppmvw THC as propane corrected to 3.0 percent CO 2. (C) Average CO emissions determined under paragraph (d)(8) of this section equal to or less than 10 parts ppmvd, corrected to 3.0 percent CO 2. (D) Excess combustion air determined under paragraph (d)(7) of this section equal to or greater than 150 percent.***E.O. 12866 R eview

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Appendix : F - 14 (ii) The manufacturer must determine a maximum inlet gas flow rate which must not be exceeded for each control device model to achieve the criteria in paragraph (d)(11)(iii) of this section. The maximum inlet gas flow rate must be included in the test report required b y paragraph (d)(12) of this section. (iii) A control device meeting the criteria in paragraph (d)(11)(i)(A) through (D) of this section must demonstrate a destruction efficiency of 95 percent for VOC regulated under this rule. (12) The owner or operator of a combustion control device model tested under this paragraph must submit the information listed in paragraphs (d)(12)(i) through (vi) in the test report. Owners or operators who claim that any of the performance test information being submitted is confidential business information (CBI) must submit a complete file including information claimed to be CBI, on a compact disc, flash drive, or other commonly used electronic storage media to the EPA. The electronic media must be clearl y marked as CBI and mailed to Attn: CBI

Officer; OAQPS CBIO Room 521; 109 T.W. Alexander Drive; RTP, NC 27711. The same file with the CBI omitted must be submitted to Oil_and_Gas_PT@EPA.GOV . (i) A full schematic of the control device and dimensions of the device components. (ii) The maximum net heating value of the device. (iii) The test fuel gas flow range (in both mass and volume). Include the maxi mum allowable inlet gas flow rate. (iv) The air/stream injection/assist ranges, if used. (v) The test conditions listed in paragraphs (d)(12)(v)(A) through (O) of this section, as applicable for the tested model. (A) Fuel gas delivery

pressure and temperature. (B) Fuel gas moisture range.***E.O. 12866 R eview

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Appendix : F - 15 (C) Purge gas usage range. (D) Condensate (liquid fuel) separation range. (E) Combustion zone temperature range. This is required for all devices that measure this parameter. (F) Excess combustion air range. (G) Flame arre stor(s). (H) Burner manifold. (I) Pilot flame indicator. (J) Pilot flame design fuel and calculated or measured fuel usage. (K) Tip velocity range. (L) Momentum flux ratio. (M) Exit temperature range. (N) Exit flow rate. (O) Wind velocity

and direction. (v i) The test report must include all calibration quality assurance/quality

control data, calibration gas values, gas cylinder certification, strip charts, or other graphic presentations of the data annotated with test times and calibration values. (e) Continuous compliance for combustion control devices tested by the manufacturer in accordance with paragraph (d) of this section. This paragraph applies to the demonstration of compliance for a combustion control device tested under the provisions in paragraph (d) of this section. Owners or operators must demonstrate that a control device achieves the performance***E.O. 12866 R eview

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Appendix : F - 16 requirements in (d)(11) of this section by installing a device tested under paragraph (d) of this section and compl yi ng with the criteria specified in paragraphs (e)(1) through (7 ) of this section. (1) The inlet gas flow rate must be equal to or less than the maximum specified by the manufacturer. (2) A pilot flame must be present at all times of operation. (3) Devices must be operated with no visible em issions, except for periods not to exceed a total of one minute during any 15 minute period. A visible emissions test using section 11 of Method 22, 40 CFR part 60, appendix A, must be performed at least once every calendar month, separated b y at least 15 day s between each test. The observation period shall be 15 minutes. (4) Devices failing the visible emissions test must follow manufacturer's repair instructions, if available, or best combustion engineering practice as outlined in the unit inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair and maintenance activities for each unit must be recorded in a maintenance and repair log and must be available for inspection. (5) Following return to operation from maintenance or repair activity , each device must pass an EPA Method 22, 40 CFR part 60, appendix A, visual observation as described in paragraph (e)(3) of this section. (6) If the owner or operator operates a combustion control device model tested under this section, an electronic copy of the performance test results required by this section shall be submitted via email to Oil_and_Gas_PT@EPA.GOV unless the test results for that model of combustion control device are posted at the following Web site: epa.gov/airquality /oilandgas/. (7) Ensure that each enclosed combustion control device is maintained in a leak free condition.***E.O. 12866 Review

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Appendix : G - 1 

### G **Equipment Component VOC Leaks at Natural Gas Processing Plants G.1**  **Applicability** (a) The group of all equipment, except compressors, within a process unit located at an onshore natural gas processing plant . (b ) Equipment associated with a compressor station, dehydration unit, sweetening unit, underground storage vessel, field gas gathering s ys tem, or liquefied natural gas unit is covered by the requirements of section G.2 if it is located at an onshore natural gas processing plant. Equipment not located at the onshore natural gas processing plant site is exempt from the requirements of section G.2. (c ) The equipment within a process unit subject to VOC emission control requirements located at onshore natural gas processing plants is exempt from this section if they are subject to and controlled according to subparts VVa, GGG or GGGa of 40 CFR part 60. 

### G.2 **Wh at**  **VOC Emission R equirements**  **A pply**  **to E quipment Components**  **at an Onshore Natural Gas Processing P lant?**  (a) You must compl y with the requirements of sections G .5 .1 (a), (b), and (d), and sections G .5 .4 through G .5 .11, except as provided in section G.3. (b) You may

elect to comply

with the requirements of sections G .6 .1 and G .6 .2, as an alternative. (c) You must compl y with the provisions of section G .7 of this section except as provided in paragraph (e) of this section. (d) You must comply

with the provisions of section G.9 .8 and G.9 .9 of this section except as provided in section G.3.***E.O. 12866 R eview

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Appendix : G - 2 (e) You must use the following instead of section G. 7 (d)(1): Each piece of equipment is presumed to be in VOC service or in wet gas service unless an owner or operator demonstrates that the piece of equipment is not in VOC service or in wet gas service. For a piece of equipment to be considered not in VOC service, it must be determined that the VOC content can be reasonabl y expected never to exceed 10.0 percent by weight. For a piece of equipment to be considered in wet gas service, it must be determined that it contains or contacts the field gas before the extraction step in the process. For purposes of determining the percent VOC content of the process fluid that is co ntained in or contacts a piece of equipment, procedures that conform to the methods described in ASTM E169 - 93, E168 - 92, or E260 - 96 must be used. 

### G **.3 What**  **E xceptions**  **Apply to the Equipment L**  **eak VOC Emission Control**  **Requirements for Equipment Components**  **at Onshore Natural Gas**  **Processing P lants?**  (a) You may

comply with the following exceptions to the provisions of section G.2(a) and (b).(b)(1) Each pressure relief device in gas/vapor service may be monitored quarterl y and within 5 day s after each pressure re lease to detect leaks by the methods specified in section G .7 (b) except as provided in section G.2(c) and in paragraph (b)(4) of this section, and section G .5 . 4(a) through (c) of this rule . (2) If an instrument reading of 500 ppm or greater is measured, a leak is detected. (3)(i) When a leak is detected, it must be repaired as soon as practicable, but no later than 15 calendar day s after it is detected, except as provided in section G .5 .9. (ii) A first attempt at repair must be made no later than 5 calendar day s after each leak is detected. (4)(i) An y pressure relief device that is located in a nonfractionating plant that is monitored only

by non - plant personnel may be monitored after a pressure release the next time***E.O. 12866 R eview

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Appendix : G - 3 the monitoring personnel are on - site, ins tead of within 5 day s as specified in paragraph (b)(1) of this section and section G.9.4(b)(1). (ii) No pressure relief device described in paragraph (b)(4)(i) of this section must be allowed to operate for more than 30 day s after a pressure release without monitoring. (c) Sampling connection sy stems are exempt from the requirements of section G .5 .9. (d) Pumps in light liquid service, valves in gas/vapor and light liquid service, pressure relief devices in gas/vapor service, and connectors in gas/vapor serv ice and in light liquid service that are located at a non - fractionating plant that does not have the design capacity to process 283,200 standard cubic meters per day (scmd) (10 million standard cubic feet per day) or more of field gas are exempt from the routine monitoring requirements of sections G .5 .2(a)(1), G .5 .7 (a), G .5 .11(a), and paragraph (b)(1) of this section. (e) Pumps in light liquid service, valves in gas/vapor and light liquid service, pressure relief devices in gas/vapor service, and connector s in gas/vapor service and in light liquid service within a process unit that is located in the Alaskan North Slope are exempt from the routine monitoring requirements of sections G .5 .2 (a)(1), G .5 .7(a), G .5 .11(a), and paragraph (b)(1) of this section. (f) An owner or operator may use the following provisions instead of section G .7 (e): (1) Equipment is in heavy liquid service if the weight percent evaporated is 10 percent or less at 150°C (302°F) as determined b y ASTM Method D86 - 96. (2) Equipment is in light liquid service if the weight percent evaporated is greater than 10 percent at 150°C (302°F) as determined b y ASTM Method D86 - 96. (g) An owner or operator may use the following provisions instead of section G .7 (b)(2): A calibration drift assessment shall be performed, at a minimum, at the end of each monitoring day . Check the instrument using the same calibration gas(es) that were used to calibrate the instrument before use. Follow the procedures specified in USEPA Method 21 of appendix A - 7 of this part, S ection 10.1, except do not adjust the meter readout to correspond to the calibration gas***E.O. 12866 R eview

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Appendix : G - 4 value. Record the instrument reading for each scale used as specified in section G .8 (e)(8). Divide these readings by

the initial calibration values for each scale and multiply by 100 to express the calibration drift as a percentage. If any calibration drift assessment shows a negative drift of more than 10 percent from the initial calibration value, then all equipment monitored since the last calibration with instrument readings below the appropriate leak definition and above the leak definition multiplied by (100 minus the percent of negative drift/divided by 100) must be re - monitored. I f any calibration drift assessment shows a positive drift of more than 10 percent from the initial calibration value, then, at the owner/operator's discretion, all equipment since the last calibration with instrument readings above the appropriate leak def inition and below the leak definition multiplied by (100 plus the percent of positive drift/divided by 100) may be re - monitored. 

### G.4 **How Do I Demonstrate I nitial**  **and C ontinued**  **C ompliance with the**  **VOC Emission Control Requirements for E quipmen**  **t Components a**  **t Onshore Natural Gas Processing P**  **lants?** You must determine initial compliance with the standards for each equipment component subject to VOC emission control requirements by the compliance date specified by your regulatory

authority b y complying with the requirements specified in paragraphs (a) through (i) of this section. For equipment components subject to VOC emission control requirements at onshore natural gas processing plants, initial and continuous compliance with the VOC requirements is demonstrate d if you are in compliance with the requirements of section G .2.***E.O. 12866 R eview

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Appendix : G - 5 

### G **.5 What VOC**  **Emission Control Requirements**  **Apply to Equipment Components at Onshore Natural Gas Processing Plants**  **G .5**  **.1 VOC**  **Emission Control Requirements: General**  (a) Each owner or operator subject to the provisions of this rule shall demonstrate compliance with the requirements of sections G .5 .1 through G .5 .10 for all equipment within 180 day s of the compliance date . (b) Compliance with sections G .5 .1 to G .5 .10 will be determined b y review o f records and reports, review of performance test results, and inspection using the methods and procedures specified in G.7 . (c)(1) An owner or operator may request a determination of equivalence of a means of emission limitation to the requirements of sec tions G .5 .2, G .5 .3, G .5 .5, G .5 .6, G .5.7, G.5.8, and G.5 .10. (2) If the permitting authority makes a determination that a means of emission limitation is at least equivalent to the requirements of sections G.5.2, G.5.3, G.5.5, G.5.6, G.5.7, G.5 .8, or sectio n G.5 .10, an owner or operator shall comply with the requirements of that determination. (d) Equipment that is in vacuum service is excluded from the requirements of sections G.5.2 through G.5 .10 if it is identified as required in section G.8 (e)(5). (e) Equipment that an owner or operator designates as being in VOC service less than 300 hr/y r is excluded from the requirements of sections G.5.2 through G.5 .11 if it is identified as required in section G.8 (e)(6) and it meets any of the conditions specif ied in paragraphs (e)(1) through (3) of this section. (1) The equipment is in VOC service onl y during startup and shutdown, excluding startup and shutdown between batches of the same campaign for a batch process. (2) The equipment is in VOC service onl y during process malfunctions or other emergencies.***E.O. 12866 R eview

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Appendix : G - 6 (3) The equipment is backup equipment that is in VOC service onl y when the primary equipment is out of service. (f)(1) If a dedicated batch process unit operates less than 365 day s during a year, an owner or operator may

monitor to detect leaks from pumps, valves, and open - ended valves or lines at the frequency

specified in the following table instead of monitoring as specified in sections G.5.2, G.5.7, and G.5 .2:

**Operating Time (percent of hours**  **during year) Equivalent Monitoring Frequency Time in Use** 

**Monthly Quarterly**  **Semiannually** 0 to <25 Quarterl y Annually Annually 25 to <50 Quarterl y Semiannually Annually 50 to <75 Bimonthly Three Quarters Semiannually 75 to 100 Monthly Quarterl y Semiannually (2) Pumps and valves that are shared among two or more batch process units that are subject to this subpart may be monitored at the frequencies specified in paragraph (f)(1) of this section, provided the operating time of all such process units is considered. (3) The monitoring frequencies specified in paragraph (f)(1) of this section are not requirements for monitoring at specific intervals and can be adjusted to accommodate process operations. An owner or operator may monitor at any

time during the specified monitoring period (e.g., month, quarter, year), provided the monitoring is conducted at a reasonable interval after completion of the last monitoring campaign. Reasonable intervals are defined in paragraphs (f)(3)(i) through (iv) of this section. (i) When monitoring is conducted quarterl y, monitoring events must be separated b y at least 30 calendar day s. (ii) When monitoring is conducted semiannuall y ( i.e. , once every 2 quarters), monitoring events must be separated by at least 60 calendar day s. (iii) When monitoring is conducted in 3 quarters per year, monitoring events must be separated b y at least 90 calendar days.***E.O. 12866 R eview

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Appendix : G - 7 (iv) When monitoring is conducted annually , monitoring events must be separated b y at least 120 calendar day s. (g) If the storage vessel is sh ared with multiple process units, the process unit with the greatest annual amount of stored materials (predominant use) is the process unit the storage vessel is assigned to. If the storage vessel is shared equally among process units, and one of the proc ess units has equipment subject to this subpart, the storage vessel is assigned to that process unit. I f the storage vessel is shared equally among process units, none of which have equipment subject to this subpart of this part, the storage vessel is assi gned to any process unit subject to subpart VV of this part. If the predominant use of the storage vessel varies from year to year, then the owner or operator must estimate the predominant use initially and reassess every

3 ye ars. The owner or operator mus t keep records of the information and supporting calculations that show how predominant use is determined. All equipment on the storage vessel must be monitored when in VOC service. **G.5 .2**  **What Equipment Component VOC Emission Control R** **equirements Apply to**  **Pu mps in Light Liquid S**  **ervice?** (a)(1) Each pump in light liquid service shall be monitored monthly to detect leaks by

the methods specified in section G.7 (b), except as provided in sections G.5 .1(c) and (f) and paragraphs (d), (e), and (f) of this section. A pump that begins operation in light liquid service after the compliance date for the process unit must be monitored for the first time within 30 days after the end of its startup period, except for a pump that replaces a leaking pump and except as provi ded in section G.5 .1(c) and paragraphs (d), (e), and (f) of this section. (2) Each pump in light liquid service shall be checked b y visual inspection each calendar week for indications of liquids dripping from the pump seal, except as provided in section G .5 .1(f). (b)(1) The instrument reading that defines a leak is specified in paragraphs (b)(1)(i) and (ii) of this section. (i) 5,000 parts per million (ppm) or greater for pumps handling poly merizing monomers;***E.O. 12866 R eview

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Appendix : G - 8 (ii) 2,000 ppm or greater for all other pumps. (2) If there are indications of liquids dripping from the pump seal, the owner or operator shall follow the procedure specified in either paragraph (b)(2)(i) or (ii) of this section. This requirement does not apply to a pump that was monitored after a prev ious weekl y inspection and the instrument reading was less than the concentration specified in paragraph (b)(1)(i) or (ii) of this section, whichever is applicable. (i) Monitor the pump within 5 day s as specified in section G.7 (b). A leak is detected if th e instrument reading measured during monitoring indicates a leak as specified in paragraph (b)(1)(i) or (ii) of this section, whichever is applicable. The leak shall be repaired using the procedures in paragraph (c) of this section. (ii) Designate the visu al indications of liquids dripping as a leak, and repair the leak using either the procedures in paragraph (c) of this section or by eliminating the visual indications of liquids dripping. (c)(1) When a leak is detected, it shall be repaired as soon as pra cticable, but not later than 15 calendar day s after it is detected, except as provided in section G.5 .9. (2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected. First attempts at repair include, but are not li mited to, the practices described in paragraphs (c)(2)(i) and (ii) of this section, where practicable. (i) Tightening the packing gland nuts; (ii) Ensuring that the seal flush is operating at design pressure and temperature. (d) Each pump equipped with a d ual mechanical seal sy stem that includes a barrier fluid sy stem is exempt from the requirements of paragraph (a) of this section, provided the requirements specified in paragraphs (d)(1) through (6) of this section are met. (1) Each dual mechanical seal sy stem is:***E.O. 12866 R eview

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Appendix : G - 9 (i) Operated with the barrier fluid at a pressure that is at all times greater than the pump stuffing box pressure; or (ii) Equipped with a barrier fluid degassing reservoir that is routed to a process or fuel gas sy stem or connected b y a closed v ent s ys tem to a control device that complies with the requirements of section G.5 .10; or (iii) Equipped with a sy stem that purges the barrier fluid into a process stream with zero VOC emissions to the atmosphere. (2) The barrier fluid sy stem is in heavy li quid service or is not in VOC service. (3) Each barrier fluid s ys tem is equipped with a sensor that will detect failure of the seal sy stem, the barrier fluid sy stem, or both. (4)(i) Each pump is checked by visual inspection, each calendar week, for indicat ions of liquids dripping from the pump seals. (ii) If there are indications of liquids dripping from the pump seal at the time of the weekl y inspection, the owner or operator shall follow the procedure specified in either paragraph (d)(4)(ii)(A) or (B) of this section prior to the next required inspection. (A) Monitor the pump within 5 day s as specified in section G.7 (b) to determine if there is a leak of VOC in the barrier fluid. If an instrument reading of 2,000 ppm or greater is measured, a leak is detec ted. (B) Designate the visual indications of liquids dripping as a leak. (5)(i) Each sensor as described in paragraph (d)(3) is checked dail y or is equipped with an audible alarm. (ii) The owner or operator determines, based on design considerations and op erating experience, a criterion that indicates failure of the seal sy stem, the barrier fluid sy stem, or both.***E.O. 12866 R eview

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Appendix : G - 10 (iii) If the sensor indicates failure of the seal s ys tem, the barrier fluid sy stem, or both, based on the criterion established in paragraph (d)(5 )(ii) of this section, a leak is detected. (6)(i) When a leak is detected pursuant to paragraph (d)(4)(ii)(A) of this section, it shall be repaired as specified in paragraph (c) of this section. (ii) A leak detected pursuant to paragraph (d)(5)(iii) of this section shall be repaired within 15 day s of detection by eliminating the conditions that activated the sensor. (iii) A designated leak pursuant to paragraph (d)(4)(ii)(B) of this section shall be repaired within 15 day s of detection by eliminating vis ual indications of liquids dripping. (e) Any pump that is designated, as described in section G.8 (e)(1) and (2), for no detectable emissions, as indicated b y an instrument reading of less than 500 ppm above background, is exempt from the requirements of paragraphs (a), (c), and (d) of this section if the pump: (1) Has no externally actuated shaft penetrating the pump housing; (2) Is demonstrated to be operating with no detectable emissions as indicated by an instrument reading of less than 500 ppm above bac kground as measured b y the methods specified in section G.7 (c); and (3) Is tested for compliance with paragraph (e)(2) of this section initially upon designation, annually , and at other times requested by the permitting authority (f) If any pump is equippe d with a closed vent s ys tem capable of capturing and transporting any leakage from the seal or seals to a process or to a fuel gas system or to a control device that complies with the requirements of section G.5 .10, it is exempt from paragraphs (a) through (e) of this section. (g) Any pump that is designated, as described in section G.8 (f)(1), as an unsafe - to monitor pump is exempt from the monitoring and inspection requirements of paragraphs (a) and (d)(4) through (6) of this section if:***E.O. 12866 R eview

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Appendix : G - 11 (1) The owner or o perator of the pump demonstrates that the pump is unsafe - to - monitor because monitoring personnel would be exposed to an immediate danger as a consequence of complying with paragraph (a) of this section; and (2) The owner or operator of the pump has a writt en plan that requires monitoring of the pump as frequently

as practicable during safe - to - monitor times, but not more frequentl y than the periodic monitoring schedule otherwise applicable, and repair of the equipment according to the procedures in paragraph (c) of this section if a leak is detected. (h) Any pump that is located within the boundary of an unmanned plant site is exempt from the weekly

visual inspection requirement of paragraphs (a)(2) and (d)(4) of this section, and the daily requirements of paragraph (d)(5) of this section, provided that each pump is visually inspected as often as practicable and at least monthly . **G.5 .3**  **What Equipment Component VOC Emission Control R** **equirements Apply to**  **C om**  **pressors?** (a) Each compressor shall be equipped with a seal sy stem that includes a barrier fluid sy stem and that prevents leakage of VOC to the atmosphere, except as provided in section G.5 .1(c) and paragraphs (h), (i), and (j) of this section. (b) Each compressor seal sy stem as required in paragraph (a) of th is section shall be: (1) Operated with the barrier fluid at a pressure that is greater than the compressor stuffing box pressure; or (2) Equipped with a barrier fluid s ys tem degassing reservoir that is routed to a process or fuel gas s ys tem or connected by a closed vent s ys tem to a control device that complies with the requirements of section G.5 .10; or (3) Equipped with a s ys tem that purges the barrier fluid into a process stream with zero VOC emissions to the atmosphere.***E.O. 12866 R eview

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Appendix : G - 12 (c) The barrier fluid s ys tem shall be in heav y liquid service or shall not be in VOC service. (d) Each barrier fluid s ys tem as described in paragraph (a) shall be equipped with a sensor that will detect failure of the seal sy stem, barrier fluid sy stem, or both. (e)(1) Each sensor as required in paragraph (d) of this section shall be checked daily or shall be equipped with an audible alarm. (2) The owner or operator shall determine, based on design considerations and operating experience, a criterion that indicates failure of the seal sy stem , the barrier fluid sy stem, or both. (f) If the sensor indicates failure of the seal s ys tem, the barrier s ys tem, or both based on the criterion determined under paragraph (e)(2) of this section, a leak is detected. (g)(1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar day s after it is detected, except as provided in section G.5 .9. (2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected. (h) A compressor is ex empt from the requirements of paragraphs (a) and (b) of this section, if it is equipped with a closed vent s ys tem to capture and transport leakage from the compressor drive shaft back to a process or fuel gas sy stem or to a control device that complies with the requirements of section G.5 .10, except as provided in paragraph (i) of this section. (i) Any compressor that is designated, as described in section G.8 (e)(1) and (2), for no detectable emissions, as indicated b y an instrument reading of less than 500 ppm above background, is exempt from the requirements of paragraphs (a) through (h) of this section if the compressor: (1) Is demonstrated to be operating with no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background, as measured by the methods specified in section G.7 (c); and***E.O. 12866 R eview

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Appendix : G - 13 (2) Is tested for compliance with paragraph (i)(1) of this section initially upon designation, annually , and at other times requested by the permitting authority . **G.5 .4**  **What Equipment Component VOC Emission Control R** **equirements Apply to**  **Pressure Relief D evice**  **s in Gas/Vapor S ervice?**  (a) Except during pressure releases, each pressure relief device in gas/vapor service shall be operated with no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background, as determined b y the methods specified in section G.7 (c). (b)(1) After each pressure release, the pressure relief device shall be returned to a condition of no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background, as soon as practicable, but no later than 5 calendar day s after the pressure release, except as provided in section G.5 .9. (2) No later than 5 calendar day s after the pressure release, the pressure relief device shall be monitored to confirm the conditions of no detectable emissions, as indicated by an instrument reading o f less than 500 ppm above background, by the methods specified in section G.7 (c). (c) Any pressure relief device that is routed to a process or fuel gas s ys tem or equipped with a closed vent s ys tem capable of capturing and transporting leakage through the pressure relief device to a control device as described in section G.5 .10 is exempted from the requirements of paragraphs (a) and (b) of this section. (d)(1) Any pressure relief device that is equipped with a rupture disk upstream of the pressure relief de vice is exempt from the requirements of paragraphs (a) and (b) of this section, provided the owner or operator complies with the requirements in paragraph (d)(2) of this section. (2) After each pressure release, a new rupture disk shall be installed upstre am of the pressure relief device as soon as practicable, but no later than 5 calendar days after each pressure release, except as provided in section G.5 .9.***E.O. 12866 R eview

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Appendix : G - 14 **G.9.5 What**  **Equipment Component VOC Emission Control R equirements**  **Apply to Sampling Connection S**  **ystems?** (a) Each sampling connection sy stem shall be equipped with a closed - purge, closed - loop, or closed - vent s ys tem, except as provided in section G.5 .1(c) and paragraph (c) of this section. (b) Each closed - purge, closed - loop, or closed - vent sy stem as re quired in paragraph (a) of this section shall comply

with the requirements specified in paragraphs (b)(1) through (4) of this section. (1) Gases displaced during filling of the sample container are not required to be collected or captured. (2) Containers that are part of a closed - purge s ys tem must be covered or closed when not being filled or emptied. (3) Gases remaining in the tubing or piping between the closed - purge s ys tem valve(s) and sample container valve(s) after the valves are closed and the sample container is disconnected are not required to be collected or captured. (4) Each closed - purge, closed - loop, or closed - vent sy stem shall be designed and operated to meet requirements in either paragraph (b)(4)(i), (ii), (iii), or (iv) of this section. (i) R eturn the purged process fluid directl y to the process line. (ii) Collect and recycle the purged process fluid to a process. (iii) Capture and transport all the purged process fluid to a control device that complies with the requirements of section G.5 .10. (iv) Collect, store, and transport the purged process fluid to any of the following s ys tems or facilities:***E.O. 12866 R eview

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Appendix : G - 15 (A) A waste management unit as defined in 40 CFR 63.111, if the waste management unit is subject to and operated in compliance with the provisions o f 40 CFR part 63, subpart G, applicable to Group 1 wastewater streams; (B) A treatment, storage, or disposal facility subject to regulation under 40 CFR part 262, 264, 265, or 266; (C) A facility

permitted, licensed, or registered b y a state to manage muni cipal or industrial solid waste, if the process fluids are not hazardous waste as defined in 40 CFR part 261; (D) A waste management unit subject to and operated in compliance with the treatment requirements of 40 CFR 61.348(a), provided all waste management units that collect, store, or transport the purged process fluid to the treatment unit are subject to and operated in compliance with the management requirements of 40 CFR 61.343 through 40 CFR 61.347; or (E) A device used to burn off - specification used oil for energy recovery in accordance with 40 CFR part 279, subpart G, provided the purged process fluid is not hazardous waste as defined in 40 CFR part 261. (c) In - situ sampling s ys tems and sampling s ys tems without purges are exempt from the requirement s of paragraphs (a) and (b) of this section. **G.5 .6**  **What Equipment Component VOC Emission Control R** **equirements Apply to Open**  **** **Ended Valves or L ines?**  (a)(1) Each open - ended valve or line shall be equipped with a cap, blind flange, plug, or a second valve, except as provided in section G.5 .1(c) and paragraphs (d) and (e) of this section. (2) The cap, blind flange, plug, or second valve shall seal the open end at all times except during operations requiring process fluid flow through the open - ended valve or line. (b) Each open - ended valve or line equipped with a second valve shall be operated in a manner such that the valve on the process fluid end is clos ed before the second valve is closed.***E.O. 12866 R eview

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Appendix : G - 16 (c) When a double block - and - bleed s ys tem is being used, the bleed valve or line may remain open during operations that require venting the line between the block valves but shall comply with paragraph (a) of this secti on at all other times. (d) Open - ended valves or lines in an emergency shutdown sy stem which are designed to open automaticall y in the event of a process upset are exempt from the requirements of paragraphs (a), (b), and (c) of this section. (e) Open - ended valves or lines containing materials which would auto - cataly ticall y poly merize or would present an explosion, serious overpressure, or other safety hazard if capped or equipped with a double block and bleed sy stem as specified in paragraphs (a) through (c) of this section are exempt from the requirements of paragraphs (a) through (c) of this section. **G.5 .7**  **What Equipment Component VOC Emission Control**  **R equirements**  **Apply to Valves in Gas/Vapor Service and in Light Liquid S**  **ervice?** (a)(1) Each valve shall be m onitored monthly to detect leaks by

the methods specified in G.7 (b) and shall comply

with paragraphs (b) through (e) of this section, except as provided in paragraphs (f), (g), and (h) of this section, section G.5 .1(c) and (f), and sections G.6.1 and G.6 .2 . (2) A valve that begins operation in gas/vapor service or light liquid service after the compliance date for the process unit must be monitored according to paragraphs (a)(2)(i) or (ii), except for a valve that replaces a leaking valve and except as prov ided in paragraphs (f), (g), and (h) of this section, section G.5 .1(c), and sections G.6.1 and G.6 .2. (i) Monitor the valve as in paragraph (a)(1) of this section. The valve must be monitored for the first time within 30 day s after the end of its startup p eriod to ensure proper installation. (ii) If the existing valves in the process unit are monitored in accordance with section G.6 .1 or section G.6 .2, count the new valve as leaking when calculating the percentage of valves leaking as described in section G .6 .2(b)(5). If less than 2.0 percent of the valves are leaking for that process unit, the valve must be monitored for the first time during the next scheduled monitoring event for existing valves in the process unit or within 90 day s, whichever comes first .***E.O. 12866 R eview

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Appendix : G - 17 (b) If an instrument reading of 500 ppm or greater is measured, a leak is detected. (c)(1)(i) Any valve for which a leak is not detected for 2 successive months may be monitored the first month of every quarter, beginning with the next quarter, until a l eak is detected. (ii) As an alternative to monitoring all of the valves in the first month of a quarter, an owner or operator may

elect to subdivide the process unit into two or three subgroups of valves and monitor each subgroup in a different month durin g the quarter, provided each subgroup is monitored every

3 months. The owner or operator must keep records of the valves assigned to each subgroup. (2) If a leak is detected, the valve shall be monitored monthly until a leak is not detected for 2 successiv e months. (d)(1) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 calendar day s after the leak is detected, except as provided in section G.5 .9. (2) A first attempt at repair shall be made no later than 5 calendar day s after each leak is detected. (e) First attempts at repair include, but are not limited to, the following best practices where practicable: (1) Tightening of bonnet bolts; (2) Replacement of bonnet bolts; (3) Tightening of packing gland nuts; (4) Injec tion of lubricant into lubricated packing. (f) Any valve that is designated, as described in section G.8 (e)(2), for no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background, is exempt from the requirements of paragraph (a) of this section if the valve:***E.O. 12866 R eview

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Appendix : G - 18 (1) Has no external actuating mechanism in contact with the process fluid, (2) Is operated with emissions less than 500 ppm above background as determined by the method specified in section G.7 (c), and (3) Is tested for compliance with paragraph (f)(2) of this section initially upon designation, annually , and at other times requested by the permitting authority . (g) Any valve that is designated, as described in section G.8 (f)(1), as an unsafe - to monitor valve is exempt from the requirements of paragraph (a) of this section if: (1) The owner or operator of the valve demonstrates that the valve is unsafe to monitor because monitoring personnel would be exposed to an immediate danger as a consequence of complying with paragraph (a) of this section, and (2) The owner or operator of the valve adheres to a written plan that requires monitoring of the valve as frequently as practicable during safe - to - monitor times. (h) Any valve that is designated, as described in section G .8 (f)(2), as a difficult - to monitor valve is exempt from the requirements of paragraph (a) of this section if: (1) The owner or operator of the valve demonstrates that the valve cannot be monitored without elevating the monitoring personnel more than 2 met ers above a support surface. (2) The process unit within which the valve is located either has less than 3.0 percent of its total number of valves designated as difficult - to - monitor by the owner or operator. (3) The owner or operator of the valve follows a written plan that requires monitoring of the valve at least once per calendar ye ar.***E.O. 12866 R eview

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Appendix : G - 19 **G.5 .8**  **What Equipment Component VOC Emission Control**  **R equirements**  **Apply to Pu**  **mps, Valves, and Connectors in Heavy Liquid Service and Pressure Relief Devices in L**  **ight Liquid**  **or H eav** **y Liquid S ervice?**  (a) If evidence of a potential leak is found by visual, audible, olfactory , or any other detection method at pumps, valves, and connectors in heav y liquid service and pressure relief devices in light liquid or heav y liquid service , the owner or operator shall follow either one of the following procedures: (1) The owner or operator shall monitor the equipment within 5 day s by the method specified in section G.7 (b) and shall compl y with the requirements of paragraphs (b) through (d) of this section. (2) The owner or operator shall eliminate the visual, audible, olfactory , or other indication of a potential leak within 5 calendar days of detection. (b) If an instrument reading of 10,000 ppm or greater is measured, a leak is detected. ( c)(1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar day s after it is detected, except as provided in section G.5 .9. (2) The first attempt at repair shall be made no later than 5 calendar day s after eac h leak is detected. (d) First attempts at repair include, but are not limited to, the best practices described under sections G.5.2(c)(2) and G.5 .7(e). **G.5 .9**  **What Delay of R** **epair of E**  **quipment Component**  **Requirements Apply**  **When Equipment C**  **om ponent**  **Leaks Have B een**  **D etected?**  (a) Delay of repair of equipment for which leaks have been detected will be allowed if repair within 15 day s is technicall y infeasible without a process unit shutdown. Repair of this equipment shall occur before the end of the ne xt process unit shutdown. Monitoring to verify repair must occur within 15 day s after startup of the process unit.***E.O. 12866 R eview

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Appendix : G - 20 (b) Delay of repair of equipment will be allowed for equipment which is isolated from the process and which does not remain in VOC service. ( c) Delay of repair for valves and connectors will be allowed if: (1) The owner or operator demonstrates that emissions of purged material resulting from immediate repair are greater than the fugitive emissions likely to result from delay

of repair, and (2) When repair procedures are effected, the purged material is collected and destroyed or recovered in a control device compl yi ng with section G.5 .10. (d) Delay of repair for pumps will be allowed if: (1) Repair requires the use of a dual mechanical seal sy s tem that includes a barrier fluid sy stem, and (2) Repair is completed as soon as practicable, but not later than 6 months after the leak was detected. (e) Delay of repair beyond a process unit shutdown will be allowed for a valve, if valve assembly replace ment is necessary during the process unit shutdown, valve assembl y supplies have been depleted, and valve assembl y supplies had been sufficientl y stocked before the supplies were depleted. Delay of repair beyond the next process unit shutdown will not be allowed unless the next process unit shutdown occurs sooner than 6 months after the first process unit shutdown. (f) When delay

of repair is allowed for a leaking pump, valve, or connector that remains in service, the pump, valve, or connector may be consid ered to be repaired and no longer subject to delay of repair requirements if two consecutive monthly monitoring instrument readings are below the leak definition.***E.O. 12866 R eview

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Appendix : G - 21 **G.5 .10**  **What VOC Emission Control R** **equirements Apply**  **for Closed Vent Systems and**  **Control D evic**  **es?** (a) Owners or operators of closed vent s ys tems and control devices used to comply with provisions of this rule shall comply with the provisions of this section. (b) Vapor recovery

s ys tems (for example, condensers and absorbers) shall be designed and operated to recover the VOC emissions vented to them with an efficiency of 95 percent or greater. (c) Enclosed combustion devices shall be designed and operated to reduce the VOC emissions vented to them with an efficiency of 95 percent or greater, or to an exit concentration of 20 ppmv, on a dry

basis, corrected to 3 percent oxygen, whichever is less stringent or to provide a minimum residence time of 0.75 seconds at a minimum temperature of 816 °C. (d) Flares used to comply with this subpart shall comply with the requirements of §60.18. (e) Owners or operators of control devices used to comply with the provisions of this rule shall monitor these control devices to ensure that they are operated and maintained in conformance with their designs. (f) Except as provided in paragraphs (i) through (k) of this section, each closed vent sy stem shall be inspected according to the procedures and schedule specified in paragraphs (f)(1) and (2) of this section. (1) If the vapor collection sy stem or closed vent sy stem is constructed of hard - piping, the owner or operator shall comply with the requirements specified in paragraphs (f)(1)(i) and (ii) of this section: (i) Conduct an initial inspection according to the procedures in section G.7 (b); and (ii) Conduct annual visu al inspections for visible, audible, or olfactory indications of leaks.***E.O. 12866 R eview

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Appendix : G - 22 (2) If the vapor collection sy stem or closed vent sy stem is constructed of ductwork, the owner or operator shall: (i) Conduct an initial inspection according to the procedures in secti on G.7 (b); and (ii) Conduct annual inspections according to the procedures in section G.7 (b). (g) Leaks, as indicated by an instrument reading greater than 500 ppmv above background or b y visual inspections, shall be repaired as soon as practicable except as provided in paragraph (h) of this section. (1) A first attempt at repair shall be made no later than 5 calendar days after the leak is detected. (2) Repair shall be completed no later than 15 calendar day s after the leak is detected. (h) Delay of repai r of a closed vent sy stem for which leaks have been detected is allowed if the repair is technicall y infeasible without a process unit shutdown or if the owner or operator determines that emissions resulting from immediate repair would be greater than the fugitive emissions likely

to result from delay

of repair. Repair of such equipment shall be complete by the end of the next process unit shutdown. (i) If a vapor collection system or closed vent s ys tem is operated under a vacuum, it is exempt from the insp ection requirements of paragraphs (f)(1)(i) and (f)(2) of this section. (j) Any parts of the closed vent system that are designated, as described in paragraph (l)(1) of this section, as unsafe to inspect are exempt from the inspection requirements of paragraphs (f)(1)(i) and (f)(2) of this section if they compl y with the requirements specified in paragraphs (j)(1) and (2) of this section: (1) The owner or operator determines that the equipment is unsafe to inspect because inspecting personnel would be expos ed to an imminent or potential danger as a consequence of complying with paragraphs (f)(1)(i) or (f)(2) of this section; and***E.O. 12866 R eview

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Appendix : G - 23 (2) The owner or operator has a written plan that requires inspection of the equipment as frequentl y as practicable during safe - to - inspect times. (k) Any parts of the closed vent system that are designated, as described in paragraph (l)(2) of this section, as difficult to inspect are exempt from the inspection requirements of paragraphs (f)(1)(i) and (f)(2) of this section if they compl y with the requirements specified in paragraphs (k)(1) through (3) of this section: (1) The owner or operator determines that the equipment cannot be inspected without elevating the inspecting personnel more than 2 meters above a support surface; and (2) The owner or operator designates less than 3.0 percent of the total number of closed vent sy stem equipment as difficult to inspect; and (3) The owner or operator has a written plan that requires inspection of the equipment at least once every

5 years. A c losed vent s ys tem is exempt from inspection if it is operated under a vacuum. (l) The owner or operator shall record the information specified in paragraphs (l)(1) through (5) of this section. (1) Identification of all parts of the closed vent system that are designated as unsafe to inspect, an explanation of why the equipment is unsafe to inspect, and the plan for inspecting the equipment. (2) Identification of all parts of the closed vent system that are designated as difficult to inspect, an explanation of wh y the equipment is difficult to inspect, and the plan for inspecting the equipment. (3) For each inspection during which a leak is detected, a record of the information specified in section G.8 (c).***E.O. 12866 R eview

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Appendix : G - 24 (4) For each inspection conducted in accordance with section G.7 (b) during which no leaks are detected, a record that the inspection was performed, the date of the inspection, and a statement that no leaks were detected. (5) For each visual inspection con ducted in accordance with paragraph (f)(1)(ii) of this section during which no leaks are detected, a record that the inspection was performed, the date of the inspection, and a statement that no leaks were detected. (m) Closed vent sy stems and control devi ces used to comply with provisions of this rule shall be operated at all times when emissions may be vented to them. **G.5 .11**  **What VOC Emission Control Requirements**  **Apply to Connectors in Gas/Vapor**  **S erv** **ice and in Light Liquid S ervice?**  (a) The owner or operat or shall initially monitor all connectors in the process unit for leaks by the later of either 12 months after the compliance date. If all connectors in the process unit have been monitored for leaks prior to the compliance date, no initial monitoring is required provided either no process changes have been made since the monitoring or the owner or operator can determine that the results of the monitoring, with or without adjustments, reliably demonstrate compliance despite process changes. If required to m onitor because of a process change, the owner or operator is required to monitor only those connectors involved in the process change. (b) Except as allowed in sections G.5 .1(c) and G.5 .10, or as specified in paragraph (e) of this section, the owner or operator shall monitor all connectors in gas and vapor and light liquid service as specified in paragraphs (a) and (b)(3) of this section. (1) The connectors shall be monitored to detect leaks by the method specified in section G.7 (b) and, as applicable, sec tion G.7 (c). (2) If an instrument reading greater than or equal to 500 ppm is measured, a leak is detected.***E.O. 12866 R eview

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Appendix : G - 25 (3) The owner or operator shall perform monitoring, subsequent to the initial monitoring required in paragraph (a) of this section, as specified in paragraphs (b)(3)(i) through (iii) of this section, and shall compl y with the requirements of paragraphs (b)(3)(iv) and (v) of this section. The required period in which monitoring must be conducted shall be determined from paragraphs (b)(3)(i) through (ii i) of this section using the monitoring results from the preceding monitoring period. The percent leaking connectors shall be calculated as specified in paragraph (c) of this section. (i) If the percent leaking connectors in the process unit was greater th an or equal to 0.5 percent, then monitor within 12 months (1 year). (ii) If the percent leaking connectors in the process unit was greater than or equal to 0.25 percent but less than 0.5 percent, then monitor within 4 years. An owner or operator may comply with the requirements of this paragraph b y monitoring at least 40 percent of the connectors within 2 years of the start of the monitoring period, provided all connectors have been monitored by the end of the 4 - ye ar monitoring period. (iii) If the percent leaking connectors in the process unit was less than 0.25 percent, then monitor as provided in paragraph (b)(3)(iii)(A) of this section and either paragraph (b)(3)(iii)(B) or (b)(3)(iii)(C) of this section, as appropriate. (A) An owner or operator shall mo nitor at least 50 percent of the connectors within 4 ye ars of the start of the monitoring period. (B) If the percent of leaking connectors calculated from the monitoring results in paragraph (b)(3)(iii)(A) of this section is greater than or equal to 0.35 p ercent of the monitored connectors, the owner or operator shall monitor as soon as practical, but within the next 6 months, all connectors that have not yet been monitored during the monitoring period. At the conclusion of monitoring, a new monitoring peri od shall be started pursuant to paragraph (b)(3) of this section, based on the percent of leaking connectors within the total monitored connectors. (C) If the percent of leaking connectors calculated from the monitoring results in paragraph (b)(3)(iii)(A) of this section is less than 0.35 percent of the monitored connectors, the***E.O. 12866 R eview

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Appendix : G - 26 owner or operator shall monitor all connectors that have not yet been monitored within 8 years of the start of the monitoring period. (iv) If, during the monitoring conducted pursuant to paragraphs (b)(3)(i) through (iii) of this section, a connector is found to be leaking, it shall be re - monitored once within 90 day s after repair to confirm that it is not leaking. (v) The owner or operator shall keep a record of the start date and end date of each monitoring period under this section for each process unit. (c) For use in determining the monitoring frequency , as specified in paragraphs (a) and (b)(3) of this section, the percent leaking connectors as used in paragraphs (a) and (b)(3) of this section shall be calculated by using the following equation: %C L = C L / C t * 100 Where: %C L = Percent of leaking connectors as determined through periodic monitoring required in paragraphs (a) and (b)(3)(i) through (iii) of this section. C L = Number of connectors measured at 500 ppm or greater, b y the method specified in X.G.7 (b). C t = Total number of monitored connectors in the process unit. (d) When a leak is detected pursuant to paragraphs (a) and (b) of this section, it shall be repaired as soon as practicable, but not later than 15 calendar day s after it is detected, except as provided in section G.5 .9. A first attempt at repair as defined in this rule shall be made no later than 5 calendar day s after the leak is detected. (e) Any connec tor that is designated, as described in section G.8 (f)(1), as an unsafe - to monitor connector is exempt from the requirements of paragraphs (a) and (b) of this section if:***E.O. 12866 R eview

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Appendix : G - 27 (1) The owner or operator of the connector demonstrates that the connector is unsafe - to monitor because monitoring personnel would be exposed to an immediate danger as a consequence of complying with paragraphs (a) and (b) of this section; and (2) The owner or operator of the connector has a written plan that requires monitoring of the connector as frequently as practicable during safe - to - monitor times , but not more frequently than the periodic monitoring schedule otherwise applicable, and repair of the equipment according to the procedures in paragraph (d) of this section if a leak is dete cted. (f) Inaccessible, ceramic, or ceramic - lined connectors. (1) Any connector that is inaccessible or that is ceramic or ceramic - lined (e.g., porcelain, glass, or glass - lined), is exempt from the monitoring requirements of paragraphs (a) and (b) of this section, from the leak repair requirements of paragraph (d) of this section, and from recordkeeping and reporting requirements. An inaccessible connector is one that meets any of the provisions specified in paragraphs (f)(1)(i) through (vi) of this section , as applicable: (i) Buried; (ii) Insulated in a manner that prevents access to the connector by a monitor probe; (iii) Obstructed b y equipment or piping that prevents access to the connector by a monitor probe; (iv) Unable to be reached from a wheeled sci ssor - lift or hydraulic - ty pe scaffold that would allow access to connectors up to 7.6 meters (25 feet) above the ground; (v) Inaccessible because it would require elevating the monitoring personnel more than 2 meters (7 feet) above a permanent support surface or would require the erection of scaffold; or (vi) Not able to be accessed at any time in a safe manner to perform monitoring. Unsafe access includes, but is not limited to, the use of a wheeled scissor - lift on unstable or uneven terrain, the use of a m otorized man - lift basket in areas where an ignition potential exists, or access would require near proximity to hazards such as electrical lines, or would risk damage to equipment.***E.O. 12866 R eview

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Appendix : G - 28 (2) If any inaccessible, ceramic, or ceramic - lined connector is observed by visual, audible, olfactory , or other means to be leaking, the visual, audible, olfactory , or other indications of a leak to the atmosphere shall be eliminated as soon as practical. (g) Except for instrumentation sy stems and inaccessible, ceramic, or ceram ic - lined connectors meeting the provisions of paragraph (f) of this section, identify the connectors subject to the requirements of this rule . Connectors need not be individually identified if all connectors in a designated area or length of pipe subject to the provisions of this rule are identified as a group, and the number of connectors subject to the requirements is indicated. 

### G.6 **Alternative S tandards**  **G.6.1 Alternative Standards for Valves** **— Allowable Percentage of Valves L**  **eaking** (a) An owner or operator may elect to compl y with an allowable percentage of valves leaking of equal to or less than 2.0 percent. (b) The following requirements shall be met if an owner or operator wishes to comply with an allowable percentage of valves leaking: (1) An owner or o perator must notify the permitting authority that the owner or operator has elected to comply

with the allowable percentage of valves leaking before implementing this alternative standard, as specified in section G.9 (d). (2) A performance test as specified in paragraph (c) of this section shall be conducted initially upon designation, annually , and at other times requested by the permitting authority . (3) If a valve leak is detected, it shall be repaired in accordance with section G.5 .7(d) and (e). (c) Perf

ormance tests shall be conducted in the following manner:***E.O. 12866 R eview

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Appendix : G - 29 (1) All valves in gas/vapor and light liquid service within the natural gas processing plant subject to VOC emission control requirements shall be monitored within 1 week by the methods specified in section G.7 (b). (2) If an instrument reading of 500 ppm or greater is measured, a leak is detected. (3) The leak percentage shall be determined b y dividing the number of valves for which leaks are detected b y the number of valves in gas/vapor and light liquid service within the natural gas processing plant subject to VOC emission control requirements. (d) Owners and operators who elect to compl y with this alternative standard shall not have a natural gas processing plant subject to the equipment component VOC emission control requirements with a leak percentage greater than 2.0 percent, determined as described in section G.7 (h). **G.6.2 Alternative Standards for Valves** **— Skip Period Leak Detection and R**  **epair** (a)(1) An owner or operator may elect to compl y with one of the alternative work practices specified in paragraphs (b)(2) and (3) of this section. (2) An owner or operator must notify the permitting authority before implementing one of the alternative work practices. (b)(1) An owner or operator shall comply initially with the requirements for valves in gas/vapor service and valves in light liquid service, a s described in section G.5 .7. (2) After 2 consecutive quarterl y leak detection periods with the percent of valves leaking equal to or less than 2.0, an owner or operator may begin to skip 1 of the quarterl y leak detection periods for the valves in gas/vapo r and light liquid service. (3) After 5 consecutive quarterl y leak detection periods with the percent of valves leaking equal to or less than 2.0, an owner or operator may begin to skip 3 of the quarterl y leak detection periods for the valves in gas/vapor and light liquid service.***E.O. 12866 R eview

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Appendix : G - 30 (4) If the percent of valves leaking is greater than 2.0, the owner or operator shall comply with the requirements as described in section G.5 .7 but can again elect to use this section. (5) The percent of valves leaking shall be determined as described in section G.7 (h). (6) An owner or operator must keep a record of the percent of valves found leaking during each leak detection period. (7) A valve that begins operation in gas/vapor service or light liquid service after the compliance date for a process unit following one of the alternative standards in this section must be monitored in accordance with section G.5 .7(a)(2)(i) or (ii) before the provisions of this section can be applied to that valve. 

### G.7 **Equipment Leak** 

**Test Methods and P**  **rocedures** (a) In conducting the performance tests, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specified in this section. (b) The owner or operator shall determine compliance with the standards in sections G.5.1 through G.5 .11, and as follows: (1) USEPA Method 21 shall be used to determine the presence of leaking sources. The instrument shall be calibrated before use each day of its use by

the procedures specified in USEPA Method 21 of appendix A - 7 of this part. The following calibration gases shall be used: (i) Zero air (less than 10 ppm of hydrocarbon in air); and (ii) A mixture of methane or n - hexane and air at a concentration no more than 2,000 ppm greater than the leak definition concentration of the equipment monitored. If the monitoring instrument's design allows for multiple calibration scales, then the lower scale shall be calibrated with a calibration gas that is no higher than 2,000 ppm above the concentration specified as a leak, and the highest scale shall be calibrated with a calibration gas that is approximately equal to***E.O. 12866 R eview

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Appendix : G - 31 10,000 ppm. I f onl y one scale on an instrument will be used during monitoring, the owner or operator need not calibrate the scales that will not be used during that day's monitoring. (2) A calibration drift assessment shall be performed, at a minimum, at the end of each monitoring day . Check the instrument using the same calibration gas(es) that were used to calibrate the i nstrument before use. Follow the procedures specified in USEPA Method 21 of appendix A - 7 of this part, Section 10.1, except do not adjust the meter readout to correspond to the calibration gas value. Record the instrument reading for each scale used as spe cified in section G.8 (e)(7). Calculate the average algebraic difference between the three meter readings and the most recent calibration value. Divide this algebraic difference by the initial calibration value and multiply

by 100 to express the calibration drift as a percentage. If any calibration drift assessment shows a negative drift of more than 10 percent from the initial calibration value, then all equipment monitored since the last calibration with instrument readings below the appropriate leak defin ition and above the leak definition multiplied by (100 minus the percent of negative drift/divided by

100) must be re - monitored. If any calibration drift assessment shows a positive drift of more than 10 percent from the initial calibration value, then, at the owner/operator's discretion, all equipment since the last calibration with instrument readings above the appropriate leak definition and below the leak definition multiplied by (100 plus the percent of positive drift/divided by

100) may

be re - monitore d. (c) The owner or operator shall determine compliance with the no - detectable - emission standards in sections G.5.2(e), G.5.3(i), G.5.4, G.5.7(f), and G.5 .10(e) as follows: (1) The requirements of paragraph (b) shall apply. (2) USEPA Method 21 of appendix A - 7 of this part shall be used to determine the background level. All potential leak interfaces shall be traversed as close to the interface as possible. The arithmetic difference between the maximum concentration indicated b y the instrument and the background level is compared with 500 ppm for determining compliance. (d) The owner or operator shall test each piece of equipment unless he demonstrates that a process unit is not in VOC service, i.e., that the VOC content would never be reasonabl y***E.O. 12866 R eview

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Appendix : G - 32 expected to exceed 10 percent b y weight. For purposes of this demonstration, the following methods and procedures shall be used: (1) Procedures that conform to the general methods in ASTM E260 - 73, 91, or 96, E168 - 67, 77, or 92, E169 - 63, 77, or 93 shall be used to determine the percent VOC content in the process fluid that is contained in or contacts a piece of equipment. (2) Organic compounds that are considered b y the permitting authority to have negligible photochemical reactivity

may be excluded from the total quantity of organic compounds in determining the VOC content of the process fluid. (3) Engineering judgment may be used to estimate the VOC content, if a piece of equipment had not been shown previously to be in service. If the permitting authority disagrees wi th the judgment, paragraphs (d)(1) and (2) of this section shall be used to resolve the disagreement. (e) The owner or operator shall demonstrate that a piece of equipment is in light liquid service b y showing that all the following conditions apply: (1) The vapor pressure of one or more of the organic components is greater than 0.3 kPa at 20 °C (1.2 in. H 2 O at 68 °F). Standard reference texts or ASTM D2879 - 83, 96, or 97 shall be used to determine the vapor pressures. (2) The total concentration of the pure organic components having a vapor pressure greater than 0.3 kPa at 20 °C (1.2 in. H 2 O at 68 °F) is equal to or greater than 20 percent b y weight. (3) The fluid is a liquid at operating conditions. (f) Samples used in conjunction with paragraphs (d), (e), and (g) of this section shall be representative of the process fluid that is contained in or contacts the equipment or the gas being combusted in the flare.***E.O. 12866 R eview

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Appendix : G - 33 (g) The owner or operator shall determine compliance with the standards of flares as follows: 1) U SEPA Method 22 of appendix A - 7 of this part shall be used to determine visible emissions. (2) A thermocouple or any other equivalent device shall be used to monitor the presence of a pilot flame in the flare. (3) The maximum permitted velocity for air assi sted flares shall be computed using the following equation: Vmax = K 1 + K2 H T Where: Vmax = Maximum permitted velocity , m/sec (ft/sec). H T = Net heating value of the gas being combusted, MJ/scm (Btu/scf). K 1 = 8.706 m/sec (metric units) = 28.56 ft/sec (Engl ish units). K2 = 0.7084 m4/(MJ - sec) (metric units) = 0.087 ft4/(Btu - sec) (English units). (4) The net heating value (H T ) of the gas being combusted in a flare shall be computed using the following equation:

= Where: K = Conversion const ant, 1.740×10 − 7 (g - mole)(MJ)/(ppm - scm - kcal) (metric units) = 4.674×10 − 6 [(g - mole)(Btu)/(ppm - scf - kcal)] (English units). C i = Concentration of sample component “i,” ppm***E.O. 12866 R eview

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Appendix : G - 34 H i = net heat of combustion of sample component “i” at 25°C and 760 mm Hg (77°F and 14. 7 psi), kcal/g - mole. (5) USEPA Method 18 of appendix A - 6 of this part or ASTM D6420 - 99 (2004) (where the target compound(s) are those listed in Section 1.1 of ASTM D6420 - 99, and the target concentration is between 150 parts per billion by volume and 100 pp mv) and ASTM D2504 - 67, 77, or 88 (Reapproved 1993) shall be used to determine the concentration of sample component “i.” (6) ASTM D2382 - 76 or 88 or D4809 - 95 shall be used to determine the net heat of combustion of component “i” if published values are not available or cannot be calculated. (7) USEPA Method 2, 2A, 2C, or 2D of appendix A - 7 of this part, as appropriate, shall be used to determine the actual exit velocity of a flare. If needed, the unobstructed (free) cross sectional area of the flare tip shall be used. (h) The owner or operator shall determine compliance with section G.6 .1 or section G.6 .2 as follows: (1) The percent of valves leaking shall be determined using the following equation: %V L = (V L / V T) * 100 Where: %V L = Percent leaking valve s. V L = Number of valves found leaking. V T = The sum of the total number of valves monitored. (2) The total number of valves monitored shall include difficult - to - monitor and unsafe - to monitor valves only

during the monitoring period in which those valves are monitored. (3) The number of valves leaking shall include valves for which repair has been delayed.***E.O. 12866 R eview

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Appendix : G - 35 (4) Any new valve that is not monitored within 30 days of being placed in service shall be included in the number of valves leaking and the total number of valves monitored for the monitoring period in which the valve is placed in service. (5) If the process unit has been subdivided in accordance with section G.5 .7(c)(1)(ii), the sum of valves found leaking during a monitoring period includes all subgroups . (6) The total number of valves monitored does not include a valve monitored to verify repair. (i) When each leak is detec ted as specified in sections G.5.2, G.5.3, G.5.7, G.5.8, G.5.11, and G.6 .2, the following requirements appl y: (1) A weatherproof and readily visible identification, marked with the equipment identification number, shall be attached to the leaking equipment. (2) The identification on a valve may be removed after it has been monitored for 2 successive mo nths as specified in section G.5 .7( c) and no leak has been detected during those 2 months. (3) The identification on a connector may be removed after it has been monitore d as specified in section G.9.7 (b)(3)(iv) and no leak has been detected during that monitoring. (4) The identification on equipment, except on a valve or connector, may be removed after it has been repaired. 

### G. **8 Recordk** **eeping and Reporting Requirements** (a) Recordkeeping requirements . Each owner or operator subject to the VOC equipment leak requirements shall comply with the recordkeeping requirements of paragraphs (a)(1) through (10).***E.O. 12866 R eview

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Appendix : G - 36 (1) An owner or operator of more than one facility subject to the requirements of section G may comply with the recordkeeping requirements for these facilities in one recordkeeping sy stem if the sy stem identifies each record by each facility . (2) The owner or operator shall record the information specified in paragraphs (a)(2)(i) through (v) of this section for each monitoring event required b y s ections G.5.2, G.5.3, G.5.7, G.5.8, G.5.11, and G.6 .2. (i) Monitoring instrument identification. (ii) Operator identification. (iii) Equipment identification. (iv) Date of monitoring. (v) Instrument reading. (3) When each leak is detected as specified in sections G.5.2, G.5.3, G.5.7, G.5.8, G.5.11, and G.6 .2, the following information shall be recorded in a log and shall be kept for 2 years in a readil y accessible location: (i) The instrument and operator identification numbers and the equipment identification number, except when indications of liquids drip ping from a pump are designated as a leak. (ii) The date the leak was detected and the dates of each attempt to repair the leak. (iii) Repair methods applied in each attempt to repair the leak. (iv) Maximum instrument reading measured b y USEPA Method 21 of appendix A - 7 of this part at the time the leak is successfull y repaired or determined to be non - repairable, except when a pump is repaired by eliminating indications of liquids dripping. (v) “Repair delayed” and the reason for the delay if a leak is not repaired within 15 calendar day s after discovery of the leak.***E.O. 12866 R eview

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Appendix : G - 37 (vi) The signature of the owner or operator (or designate) whose decision it was that repair could not be effected without a process shutdown. (vii) The expected date of successful repair of the leak if a leak is not repaired within 15 day s. (viii) Dates of process unit shutdowns that occur while the equipment is unrepaired. (ix) The date of successful repair of the leak. (4) The following information pertaining to the design requirements for clos ed vent sy stems and control devices described in section G.5 .10 shall be recorded and kept in a readily accessible location: (i) Detailed schematics, design specifications, and piping and instrumentation diagrams. (ii) The dates and descriptions of any changes in the design specifications. (iii) A description of the parameter or parameters monitored, as required in section G.5 .10(e), to ensure that control devices are operated and maintained in conformance with their design and an explanation of why that parameter (or parameters) was selected for the monitoring. (iv) Periods when the closed vent sy stems and control devices required in sections G.5.2, G.5.3, G.5.4, and G.5 .5 are not operated as designed, including periods when a flare pilot light does not hav e a flame. (v) Dates of startups and shutdowns of the closed vent sy stems and control devices required in sections G.5.2, G.5.3, G.5.4, and G.5 .5. (5) The following information pertaining to all equipment subject to the requirements in sections G.5.1 to G. 5 .11 shall be recorded in a log that is kept in a readil y accessible location: (i) A list of identification numbers for equipment subject to the requirements of this rule .***E.O. 12866 R eview

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Appendix : G - 38 (ii)(A) A list of identification numbers for equipment that are designated for no de tectable emissions under the provisions of sections G.5.2(e), G.5.3(i), and G.5 .7(f). (B) The designation of equipment as subject to the requirements of sections G.5.2(e), G.5 .3(i), or section G.5 .7(f) shall be signed b y the owner or operator. Alternativel y, the owner or operator may

establish a mechanism with their permitting authority that satisfies this requirement. (C) A list of equipment identification numbers for pressure relief devices required to comply with section G.5 .4. (iii)(A) The dates of each compliance test as required in sections G.5.2(e), G.5.3(i), G.5.4, and G.5 .7(f). (B) The background level measured during each compliance test. (C) The maximum instrument reading measured at the equipment during each compliance test. (iv) A list of identification numbers for equipment in vacuum service. (v) A list of identification numbers for equipment that the owner or operator designates as operating in VOC service less than 300 hr/yr in accordance with section G.5 .1(e), a description of the condi tions under which the equipment is in VOC service, and rationale supporting the designation that it is in VOC service less than 300 hr/y r. (vi) The date and results of the weekl y visual inspection for indications of liquids dripping from pumps in light liquid service. (vii) Records of the information specified in paragraphs (a)(5)(vii)(A) through (F) of this section for monitoring instrument calibrations conducted according to sections 8.1.2 and 10 of USEPA Method 21 of appendix A - 7 of this part and section G.7 (b). (A) Date of calibration and initials of operator performing the calibration.***E.O. 12866 R eview

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Appendix : G - 39 (B) Calibration gas cylinder identification, certification date, and certified concentration. (C) Instrument scale(s) used. (D) A description of any corrective action taken if the meter readout could not be adjusted to correspond to the calibration gas value in accordance with section 10.1 of USEPA Method 21 of appendix A - 7 of this part. (E) Results of each calibration drift assessment required by section G.7 (b)(2) (i.e., instrument reading for calibration at end of monitoring day and the calculated percent difference from the initial calibration value). (F) If an owner or operator makes their own calibration gas, a description of the procedure used. (viii) The connector mo nitoring schedule for each process unit as specified in section G.9.7 (b)(3)(v). (ix) Records of each release from a pressure relief device subject to section G.5 .4. (6) The following information pertaining to all valves subject to the requirements of secti on G.5 .7(g) and (h), all pumps subject to the requirements of section G.5 .2(g), and all connectors subject to the requirements of section G.5 .11(e) shall be recorded in a log that is kept in a readil y accessible location: (i) A list of identification numbers for valves, pumps, and connectors that are designated as unsafe - to - monitor, an explanation for each valve, pump, or connector stating why the valve, pump, or connector is unsafe - to - monitor, and the plan for monitoring each valve, pump, or connector. (ii ) A list of identification numbers for valves that are designated as difficult - to - monitor, an explanation for each valve stating why the valve is difficult - to - monitor, and the schedule for monitoring each valve.***E.O. 12866 R eview

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Appendix : G - 40 (7) The following information shall be recorded for valves compl yi ng with section G.6 .2: (i) A schedule of monitoring. (ii) The percent of valves found leaking during each monitoring period. (8) The following information shall be recorded in a log that is kept in a readily accessible location: (i) D esign criterion required in sections G.5.2(d)(5) and G.5 .3(e)(2) and explanation of the design criterion; and (ii) Any changes to this criterion and the reasons for the changes. (A) The following information shall be recorded in a log that is kept in a readily accessible location for use in determining exemptions: ( 1 ) An analy sis demonstrating the design capacity of the natural gas processing plant, ( 2 ) A statement listing the feed or raw materials and products from the processing plant(s) and an anal ys is d emonstrating whether these chemicals are heav y liquids or beverage alcohol, and ( 3 ) An analy sis demonstrating that equipment is not in VOC service. (9) Information and data used to demonstrate that a piece of equipment is not in VOC service shall be record ed in a log that is kept in a readily accessible location. (10) The following recordkeeping requirements apply to pressure relief devices. (i) When each leak is detected, a weatherproof and readil y visible identification, marked with the equipment identification number, must be attached to the leaking equipment. The identification on the pressure relief device may be removed after it has been repaired.***E.O. 12866 R eview

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Appendix : G - 41 (ii) When each leak is detected as specified in section G.3(b)(2), the following information must be recorded in a log and shall be kept for 2 ye ars in a readily accessible location: (A) The instrument and operator identification numbers and the equipment identification number. (B) The date the leak was detected and the dates of each attempt to repair the leak. (C) Repair methods applied in each attempt to repair the leak. (D) “Above 500 ppm” if the maximum instrument reading measured b y the methods specified in paragraph (a) of this section after each repair attempt is 500 ppm or greater. (E) “Repair d elayed” and the reason for the delay if a leak is not repaired within 15 calendar day s after discovery of the leak. (F) The signature of the owner or operator (or designate) whose decision it was that repair could not be effected without a process shutdown . (G) The expected date of successful repair of the leak if a leak is not repaired within 15 day s. (H) Dates of process unit shutdowns that occur while the equipment is unrepaired. (I) The date of successful repair of the leak. (J) A list of identification numbers for equipment that are designated for no detectable emissions und er the provisions of section G.5 .4 (a). The designation of equipment subject to the provisions of section G.5 .4 (a) must be signed b y the owner or operator. (b) Reporting requirement s . Each owner or operator subject to the VOC equipment leak requirements shall comply with the reporting requirements of paragraphs (b)(1) through (5).***E.O. 12866 R eview

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Appendix : G - 42 (1) Each owner or operator subject to the equipment leak VOC emission control requirements of section G. 5 shall submit semiannual reports to the permitting authority beginning 6 months after a facility becomes subject to VOC emission control requirements of section G. (2) The initial semiannual report to the permitting authority shall include the following i nformation: (i) Process unit identification. (ii) Number of valves subject to the requirements of section G.5 .7, excluding those valves designated for no detectable emissions under the provisions o f section G.5 .7(f). (iii) Number of pumps subject to the re quirements of section G.5 .2, excluding those pumps designated for no detectable emissions und er the provisions of section G.5 .2(e) and those pumps complying with section G.5 .2(f). (iv) Number of compressors subject to the requirements of section G.5 .3, exc luding those compressors designated for no detectable emissions und er the provisions of section G.5 .3(i) and those compre ssors complyingwith section G.5 .3(h). (v) Number of connectors subject to the requirements of section G.9.11. (vi) Number of pressure relief devices subject to the requirements, except for those pressure relief devices designated for no detectable emissions und er the provisions of section G.5 .4 (a) and those pressure relief devic es compl ying with section G.5 .4 (c). (3) All semiannual rep orts to the permitting authority shall include the following information: (i) Process unit identification. (ii) For each month during the semiannual reporting period,***E.O. 12866 R eview

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Appendix : G - 43 (A) Number of valves for which leaks were dete cted as described in section G.5.7(b) or section G.6 .2, (B) Number of valves for which leaks were not rep aired as required in section G.5 .7(d)(1), (C) Number of pumps for which leaks were dete cted as described in section G.5 .2(b), (d)(4)(ii)(A) or (B), or (d)(5)(iii), (D) Number of pumps for whic h leaks were not rep aired as required in section G.5 .2(c)(1) and (d)(6), (E) Number of compressors for which leaks were dete cted as described in section G.5 .3(f), (F) Number of compressors for which leaks were not rep aired as required in section G.5 .3(g)(1 ), (G) Number of connectors for which leaks were detecte d as described in section G.9.7 (b) (H) Number of connectors for which leaks were not repaired as required in section G.9.7 (d), and (I) The facts that explain each delay of repair and, where appropriat e, wh y a process unit shutdown was technically infeasible. (iii) An owner or operator must include the following information in all semiannual reports: (A) Number of pressure relief devices for which leaks were detected; and (B) Number of pressure relief d evices for which leaks were not repaired. (iv) Dates of process unit shutdowns which occurred within the semiannual reporting period.***E.O. 12866 R eview

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Appendix : G - 44 (v) Revisions to items reported according to paragraph (b)(1) of this section if changes have occurred since the initial report or subsequent revisions to the initial report. (4) An owner or operator electing to comply with the provisions of section G.6.1 or section G.6 .2 shall notify the permitting authority of the alternative standard selected 90 day s before implementing ei ther of the provisions. (5) An owner or operator shall report the results of all performance tests to the permitting authority . 

### G.9 **Definitions** Equipment , as used in the standards and requirements in this rule relative to the equipment leaks of VOC from onshore natural gas processing plants, means each pump, pressure relief device, open - ended valve or line, valve, and flange or other connector that is in VOC service or in wet gas service, and any device or s yst em required b y those same standards and requirements in this rule . Gas processing plant process unit means equipment assembled for the extraction of natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or other op erations associated with the processing of natural gas products. A process unit can operate independentl y if supplied with sufficient feed or raw materials and sufficient storage facilities for the products. Natural gas processing pla nt (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. A Joule - Thompson valve, a dew point depression valve, or an isolated or standalone Joule - Thomps on skid is not a natural gas processing plant. Onshore means all facilities except those that are located in the territorial seas or on the outer continental shelf.***E.O. 12866 Review

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### H **Pneumatic Pumps: VOC Emissions Control Requirements H.1**  **Applicability** Each pneumatic pump, which is a natural gas - driven chemical/methanol or natural gas driven diaphragm pump located at a natural gas processing plant or locations between the wellhead and point of custody transfer to the natural gas transmission and storage segment for which a control device is located on site . For purposes of the requirements specified in this section, we refer to these pumps as gas - driven pneumati c pumps. 

### H.2 **What VOC Emission Reduction Requirements Apply to Natural Gas**   ** D** **riven Pneumatic P**  **umps?** For each gas - driven pneumatic pump, you must comply with the VOC emission control requirements, based on natural gas as a surrogate for VOC, in either paragr aph (a)(1) or (b)(1) of this section, as applicable. (a)(1) Each gas - driven pneumatic pump at a natural gas processing plant must have a natural gas emission rate of zero. (2) Each gas - driven pneumatic pump at a natural gas processing plant must be t agged with the date the gas - driven pneumatic pump is required to comply with the model rule (as established by

the regulatory

authority) that allows traceability to the records for that gas - dri ven pneumatic pump as required in section H.5(a)(1 )(i). (b)(1) Each gas - driven pneumatic pump located between the wellhead and point of custody transfer to the natural gas transmission and storage segment, for which a control device is located on site, must reduce natural gas emissions by 95 percent , except as provided in paragraph (b)(2) of this section . (2) You are not required to install a control device solely for the purposes of complying with the 95 percent reduction. I f you do not have a control device installed on site by the***E.O. 12866 R eview

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Appendix : H - 2 compliance date, then yo u must comply i nstead with the provisions of paragraph (b)(2)(i) and (ii) of this section. (i) Submit a certification in accordance with H.5(a)(1)(i). (ii) If you subsequentl y i nstall a control device, you are no longer required to submit the certification in H.5(a)(1) (i) and must be in compliance with the requirements of paragraph (b)(1) of this section within 30 day s of installation of the control device. Compliance with this requirement should be reported in the next annual report in accordance with H.5(a)(1)(iii). ( 3) Each gas - driven pneumatic pump located between the wellhead and point of custody transfer to the natural gas transmission and storage segment for which a control device is located on site must be tagged with the date that the pneumatic pump must comply with the model rule (as established b y the regulatory authority) that allows traceab ility to the records for that gas driven pneumatic pump as required in section H.5(a)(1)(ii ). ( 4 ) If you use a control device to reduce emissions, you must connect the gas - driven pneumatic pump subject to VOC emission control requirements through a closed vent sy stem that meets the requirements of section D.1(b) and routed to a control device that meets the conditions specified in section E.1. As an alternative to routing the closed vent sy stem to a control device, you may route the closed vent system to a process. (c) You must demonstrate initial compliance by the compliance date specified by your regulatory

authority b y demonstrating compliance with standards that apply to gas - driven pneum atic pump sources subject to VOC emission requirements as required by section H.3. (d) You must demonstrate continuous compliance with standards that appl y to gas - driven pneumatic pump sources subject to VOC emission requirements as required by section H.4 . (e) You must perform the required recordkeeping, and reporting as required by section H.5.***E.O. 12866 R eview

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Appendix : H - 3 

### H.3 **Initial Compliance Demonstration Requirements** You must demonstrate initial compliance by the compliance date specified by your regulatory

authority b y demonstrating compliance with the VOC emission control requirements for natural gas - driven pneumatic pumps specified in paragraphs (a) through (e) of this section, as applicable. (a) You own or operate a natural gas - driven pneumatic pump located at a natural gas p rocessing plant and your gas - driven chemical/methanol or diaphragm pump is driven by a gas other than natural gas and therefore emits zero natural gas. (b) You own or operate a natural gas - driven pneumatic pump located between the wellhead and point of cus tody transfer to the natural gas transmission and storage segment and yo ur gas - driven pneumatic pump is controlled by at least 95 percent where a control device is available at the site. (c) You must tag each natural gas - driven pneumatic pump subject to VOC emission requirements according to the requirements of section H.2 (a)(2 ) or (b)(2), as applicable. (d) You must include a listing of the natural gas - drive n pneumatic pump subject to VOC emission requirements specified in paragraphs H.2 (a) (1) and H.2(b)(1) in the initial annual report submitted for your natural gas - driven pneumatic pump according to the requirements of section H.5(b). (e) You must maintain the records as specified in section H.5(a) for each natural gas driven chemical/methanol or diaphragm pump subject to VOC emission control requirements of section H. 

### H.4 **Continuous Compliance Demonstration Requirements** You have demonstrated continuous compliance for each natural gas - driven pneumatic pump by compl yi ng with the requirements of paragraph (a) and (b ) of this section.***E.O. 12866 R eview

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Appendix : H - 4 (a) You must reduce VOC emissions from the natural gas - driven pneumatic pump by 95 percent or greater. (b) For each control device used to reduce emissions, you must demonstrate continuous compliance with the performanc e requirements of section H.2(a)(1) and (b)(1) using the procedures specified in paragraphs (b)(1) through (7) of this section. If you use a condenser as the control device to achieve the requirements specified in section H.2, you must demonstrate compliance according to paragraph (b)(8) of this section. You may switch between compliance with paragraphs (b)(1) through (7) of this section and compliance with paragraph (b)(8) of this section only

after at least 1 year of operatio n in compliance with the selected approach. You must provide notification of such a change in the compliance method in the next annual report, as required in section H.5 (b)(1) , following the change. (1) You must operate below (or above) the site specific m aximum (or minimum) parameter value established according to the requirements of section E.2(f)(1). (2) You must calculate the daily average of the applicable monitored parameter in accordance with section E.2(e) except that the inlet gas flow rate to the control device must not be averaged. (3) Compliance with the operating parameter limit is achieved when the daily average of the monitoring parameter value calculated under paragraph (b)(2) of this section is either equal to or greater than the minimum mon itoring value or equal to or less than the maximum monitoring value established under paragraph (b)(1) of this section. When performance testing of a combustion control device is conducted b y the device manufacturer as specified in section F(d), compliance with the operating parameter limit is achieved when the criteria in section F(e) are met. (4) You must operate the continuous monitoring system required in section E.2(a) at all times the source is operating, except for periods of monitoring system malfun ctions, repairs associated with monitoring s ys tem malfunctions, and required monitoring sy stem quality assurance or quality control activities (including, as applicable, s ys tem accuracy audits and required zero and span adjustments). A monitoring s ys tem malfunction is any sudden,***E.O. 12866 R eview

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Appendix : H - 5 infrequent, not reasonably preventable failure of the monitoring s ys tem to provide valid data. Monitoring s ys tem failures that are caused in part by poor maintenance or careless operation are not malfunctions. You are required to c omplete monitoring s ys tem repairs in response to monitoring sy stem malfunctions and to return the monitoring sy stem to operation as expeditiously

as practicable. (5) You may

not use data recorded during monitoring s ys tem malfunctions, repairs associated wi th monitoring s ys tem malfunctions, or required monitoring sy stem quality assurance or control activities in calculations used to report emissions or operating levels. You must use all the data collected during all other required data collection periods to assess the operation of the control device and associated control sy stem. (6) Failure to collect required data is a deviation of the monitoring requirements, except for periods of monitoring sy stem malfunctions, repairs associated with monitoring s ys tem malfunctions, and required quality monitoring s ys tem quality assurance or quality

control activities (including, as applicable, sy stem accuracy audits and required zero and span adjustments). (7) If you use a combustion control device to me et the requirement s of section H.2 and yo u demonstrate compliance using the test procedures specified in section F(b), you must comply with paragraphs (b)(7)(i) through (iv) of this section. (i) A pilot flame must be present at all times of operation. (ii) Devices must be o perated with no visible emissions, except for periods not to exceed a total of one minute during any 15 minute period. A visible emissions test using section 11 of Method 22, 40 CFR part 60, appendix A, must be performed at least once every calendar month, separated b y at least 15 days between each test. The observation period shall be 15 minutes. (iii) Devices failing the visible emissions test must follow manufacturer's repair instructions, if available, or best combustion engineering practice as outline d in the unit inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair***E.O. 12866 R eview

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Appendix : H - 6 and maintenance activities for each unit must be recorded in a maintenance and repair log and must be available for inspection. (iv) Following return to operation from maintenance or repair activity , each device must pass a Method 22, 40 CFR part 60, appendix A, visual observation as described in paragraph (b)(7)(ii) of this section. (8) If you use a condenser as the control device to achieve th e percent reduction performance req

uirements specified in section H.2(b)(1 ), you must demonstrate compliance using the procedures in paragraphs (b)(8)(i) through (v) of this section. (i) You must establish a site - specific condenser performance curve according to section E.2(f)(2). (ii) You must calculate the daily average condenser outlet temperature in accordance with section E.2(e). (iii) You must determine the condenser efficiency for the current operating day using the daily average condenser outlet temperature calculated under paragraph (b)(8)(ii) of this section and the condenser performance curve established under paragraph (b)(8)(i) of this section. (iv) You must calculate the 365 - day rolling average TOC emission reduction, as appropriate, from the condenser efficiencies as determined in paragraph (b)(8)(iii) of this section. ( 1 ) If you have less than 120 days of data for determining average TOC emission reduction, you must calculate the average TOC emission reduction for the first 120 days of operation. You have demonstrated compliance with the overall 95 percent reduction requirement if the 120 - day

average TOC emission reduction is equal to or greater than 95.0 percent. ( 2 ) After 120 day s and no more than 364 day s of operation, you must calculate th e average TOC emission reduction as the TOC emission reduction averaged over the number of day s of operation where you have data. You have demonstrated compliance with the overall 95 percent reduction requirement, if the average TOC emission reduction is e qual to or greater than 95 percent.***E.O. 12866 R eview

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Appendix : H - 7 (v ) If you have data for 365 days or more of operation, you have demonstrated compliance with the TOC emission reduction if the rolling 365 - day average TOC emission reduction calculated in paragraph (b)(8)(iv) of this se ction is equal to or greater than 95 percent. (3) You must submit the annual report required b y section H.5(b)(1) and maintain the records as specified in section H.5(a)(1). 

### H.5 **Recordk eeping and Reporting Requirements**  (a) Recordkeeping requirements . (1) For each applicable natural gas - driven pneumatic pump subject to VOC emission control requirements, you must maintain the records identified in paragraphs (a)(1)(i) and (ii) of this section. (i) Records of the date that an individual natural gas - driven pne umatic pump is required to comply

with the model rule (as specified by the regulatory

authority) , location and manufacturer specifications for each natural gas - driven pneumatic pump. (ii) Records of deviations in cases where the natural gas - driven pneumati c pump was not operated in compliance with the requirements specified in section H.2. (iii) Records of the control device installation date and the location of sites containing natural gas - driven pneumatic pumps at which a control device was installed, where previousl y there was no control device at the site. (b) Reporting R equirements . (1) For each natural gas - driven pneumatic pump subject to VOC emission control requirements, annual reports are required to include the information specified in paragraphs (b)(1)(i) through (iv) of this section. (i) In the initial annual report, a statement that there is no control device on site, if applicable.***E.O. 12866 R eview

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Appendix : H - 8 (ii) An identification of each natural gas - driven pneumatic pump, including the identification information specifie d in section H.2(a)(2) or section H.2(b)(2). (iii) An identification of any sites which contain natural gas - driven pneumatic pumps and which installed a control device during the reporting period, where there was no control device previously

at the site. ( iv) Records of deviations specified in paragraph (a)(1)(ii) of this section that occurred during the reporting period. 

### H.6 **Definitions** Chemical/methanol or diaphragm pump means a gas - driven positive displacement pump ty picall y used to inject precise amounts of chemicals into process streams or circulate glycol c ompounds for freeze protection. Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. A Joule - Thompson valve, a dew depression valve, or a standalone Joule - Thompson skid is not a natural gas processing plant. Natural gas - driven chemical/methanol or diaphragm pump means a chemical or methanol injection or circulation pump or a diaphragm pump powered by pressurized natural gas.***E.O. 12866 R eview

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I - 8 

### I **Fugitive Emissions Components**  **VOC Emissions Control Requirements I.1**  **Applicability** (a) The collection of fugitive emission components at a well site. (b) The collection of fugitive emission components at a compresso r station. 

### I.2 **What VOC Emission Control R equireme**  **nts App ly to the Collection of**  **Fugitive Emission Components at a Well Site and a Compressor Station ?**  For fugitive emissions, VOC emission control requirements appl y to the collection of fugitive emission components at a well site and compressor station each well site and compressor station site , as specified in paragraphs (a) through (e ) of this section for mon itoring the collection of fugitive emission components. These requirements are independent of the closed vent s ys tem and control requirements in section D. ( a) You must monitor all fugitive emission components, as defined in section I .6, in accordance with paragraphs (b) through ( d) . You must repair all sources of fugitive emissions in accordance with paragraph (e). You must keep records in accordance and report in accordance with section I .5(a). For purposes of this section, fugitive emissions are defined as: any visible emission from a fugitive emission component using optical gas imaging. (b ) You must develop corporate - wide fug itive emissions monitoring plan that cover s the collection of fugitive emission components at well site s and compressor station s in accordance with paragraph (c ) of this section, and you must develop a site - specific fugitive emissions monitoring plan specific to each collection of f ugitive emission components at a well site and each collection of fugitive emission components at a compressor station in accordance with paragraph (d) of this section. Alternatively , you may develop a site - specific plan for each collection of fugitive emi ssion components at a well site and each collection of fugitive emission components at a compressor station that covers both the corporate - wide and site - specific plans.***E.O. 12866 R eview

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I - 8 (c ) Your corporate - wide monitoring plan must include the elements specified in paragr aphs (c)(1) through (c)(8 ) of this section, as a minimum. (1) Frequency

for conducting survey s. Monitoring s urvey s must be conducted at least as frequentl y as required b y sections I.3 and section I.4 of this section. (2) Technique for determining fugitiv e emissions . (3) Manufacturer and model number of fugitive emission detection equipment to be used. (4) Procedures and timeframes for identifying and fixing fugitive emission components from which fugitives are detected, including timeframes for fugitive emission components that are unsafe to repair. Your repair schedule must meet the requirements of paragraph (e) of this section at a minimum. (5) Procedures and timeframes for verifying fugitive emission component repairs. (6) Records that will be kept and the length of time records will be kept. (7) Y our plan must also include the ele ments specified in paragraphs (c )(7)(i) through (vii). (i) Verification that your optical gas imaging equipment meets the specifications of paragraphs (c )(7)(i)(A) and (B ) of this section. This verification is an initial verification and may either be performed b y the facility, b y the manufacturer, or b y a third party. For purposes of complying with the fugitive emissions monitoring program with optical gas imaging, a fugitive emission is defined as any visible emissions observed using optical gas imaging. (A) Your optical gas imaging equipment must be capable of imaging gases in the spectral range for the compound of highest concentration in the potential fugitive emissio ns. (B) Your optical gas imaging equipment must be capable of imaging a gas that is half methane, half propane at a concentration of ≤10,000 ppm at a flow rate of ≥60 g/hr from a quarter inch diameter orifice.***E.O. 12866 R eview

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I - 8 (ii) Procedure for a dail y verification chec k. (iii) Procedure for determining the operator’s maximum viewing distance from the equipment and how the operator will ensure that this distance is maintained. (iv) Procedure for determining maximum wind speed during which monitoring can be performed an d how the operator will ensure monitoring occurs onl y at wind speeds below this threshold. (v) Procedures for conducting survey s, including the items specified in paragraphs ( c )(7)(v)(A) through (C) of this section. (A) How the operator will ensure an ad equate thermal background is present in order to view potential fugitive emissions. (B) How the operator will deal with adverse monitoring conditions, such as wind. (C) How the operator will deal with interferences (e.g., steam). (vi) Training and experience needed prior to performing surveys. (vii) Procedures for calibration and maintenance. Procedures should comply with those recommended b y the manufacturer. ( d) Your site - specific monitoring plan must include the elements specified in paragraphs (d)( 1) through (d)(3 ) of this section, as a minimum. (1) Deviations from your corporate - wide plan. (2) Sitemap. (3) Y our plan must also include your defined walking path. The walking path must ensure that all fugitive emissions components are within sight of the path and must account for interferences.***E.O. 12866 R eview

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I - 8 (e) Each monitoring survey shall observe each fugitive emission component s for fugitive emissions. ( f) (1) Each identified source is required to monitor fugitive emission components as specified in section I.3 and I .4. Identified f ugitive emissions shall be repaired or replaced as soon as practicable, but no later than 15 calendar days after detection of the fugitive emissions. I f the repair or replacement is technicall y infeasible or unsafe to repair during operation of the unit, the repair or replacement must be completed during the next scheduled shutdown or withi n 6 months, whichever is sooner. (2 ) Each repaired or replace d fugitive emissions component must be resurveyed as soon as practical, but no lat er than 15 day s after completion of the repair or replacement, to ensure that there is no leak. (i) For repairs that cannot be made during the monitoring survey when the fugitive emissions are initially

found, the operator may

resurvey the repaired fugitiv e emissions components using either Method 21 or optical gas imaging within 15 day s of finding such fugitive emissions. (ii) Operators that use Method 21 to resurvey the repaired fugitive emissions components, are subject to the resurvey provisions specifi ed in paragraphs ( e )(2)(ii)(A) and (B). (A) A fugitive emissions component is repaired when the Method 21 instrument indicates a concentration of 10,000 ppm or less . (B) Operators must use the Method 21 monitoring requirements specified in section G.3(g). (iii) Operators that use optical gas imaging to resurvey the repaired fugitive emissions components, are subject to the resurvey provisions specified in paragraphs ( e )(2)(iii)(A) and (B). (A) A fugitive emissions component is repaired when the optical ga s imaging instrument shows no indication of visible emissions.***E.O. 12866 R eview

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I - 8 (B) Operators must use the optical gas imaging monitoring requirements specified in paragraph ( a) of this section . 

### I.3 **Initial Compliance Demonstration** (a) Each well site with a collection of f ugitive emissions components must conduct an initial monitoring survey

within 30 day s of being subject to VOC emission control requirements of section I . (b) Each compressor station site with a collection of fugitive emissions components must conduct an i nitial monitoring survey within 30 day s of being subject to VOC emission control requirements of section I.2 . 

### I.4 **Continuous Compliance Demonstration** (a) A monitoring survey

of each collection of fugitive emissions components at a well site and a compressor station site subject to VOC emission control requirements under section I shall be conducted at least semiannually after the initial survey . Consecutive semiannual monitoring survey s shall be conducted at least four months apart. (b) The monito ring frequency specified in paragraph (a) of this section shall be increased to quarterl y in the event that two consecutive semiannual monitoring surveys detect fugitive emissions at 1 percent or more of the well site or compressor station fugitive emissio n components subject to VOC emission control requirements under section I. (c) The monitoring frequency specified in paragraph (a) of this section may be decreased to annual in the event that two consecutive semiannual survey s detect no fugitive emission s at less than 1 percent of the fugitive emissions components at the well site or compressor station subject to VOC emission control requirements under section I. The monitoring frequency shall return to semiannual if an annual survey detects fugitive emis sions at 1 percent or more of the fugitive emission components at the well site or compressor station subject to VOC emission control requirements under section I.***E.O. 12866 R eview

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I - 8 

### I.5 **Recordk eeping and Reporting Requirements**  (a) Records for each monitoring survey shall be maintained as specified in paragraphs (a)(1) through (6) of this section and must maintain, at a minimum, the information specified in paragraphs (a)(1) through (a)(6) of this section . (1) Date of the survey . (2) Beginning and end time of the survey . (3) Name of operator(s) performing survey . Y ou must note the training and experience of the operator. (4) Ambient temperature, sky conditions, and maximum wind speed at the time of the survey . (5) Any deviations from the monitoring plan or a statement th at there were no deviations from the monitoring plan. (6) Documentation of each source of fugitive emission s (e.g. fugitive emissions component) , including the information specified in paragraphs (a)(6)(i) through (iv ) of this section. (i) L ocation. (ii ) One or more digital photographs of each required monitoring survey being performed. The digital photograph must include the date the photograph was taken and the latitude and longitude of the well site or compressor station subject to VOC emission contro l requirements under section Iimbedded within or stored with the digital file. As an alternative to imbedded latitude and longitude within the digital photograph, the digital photograph may consist of a photograph of the monitoring survey being performed with a photograph of a separately operating GI S device within the same digital picture, provided the latitude and longitude output of the GIS unit can be clearl y read in the digital photograph.***E.O. 12866 R eview

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I - 8 (iii) The date of the successful repair of the fugitive emissi on component. (iv) The instrument used to resurvey a repaired fugitive emissions component that could not be repaired during the initial fugitive emission finding. (b) Annual reports shall be submitted for each well site and compressor station subject to VOC emission control requirements under section Ithat include the information specified in paragraph (a) of this section for each monitoring survey conducted during the year. Multiple well sites or compressor stations subject to VOC emission control requirements under section I may be included in a single annual report. 

### I.6 **Definitions** Compressor station site means any permanent combination of one or more compressors that move natural gas at increased pressure into gathering or transmission pipelines, or into storage. Fugitive emissions component means any component that has the potential to emit fugitive emi ssions of VOC at a well site or compressor station, , including but not limited to valves, connectors, pressure relief devices, open - ended lines, access doors, flanges, closed vent sy stems, thief hatches or other openings on a storage vessels, agitator seals, distance pieces, crankcase vents, blowdown vents, pump seals or diaphragms, compressors, separators, pressure vessels, deh ydrators, heaters, instruments, and meters. Devices that vent as part of normal operations, such as natural gas - driven pneumatic c ontroller s or natural gas - driven pump s , are not fugitive emissions components, insofar as the gas discharged from the device’s vent is not considered a fugitive emission. Emissions originating from other than the vent, such as the seals around the bellows of a diaphragm pump, would be considered fugitive emissions. Well site means one or more areas that are directl y disturbed during the drilling and subsequent operation of, or affected b y, production facilities directl y associated with any oil well, natural gas well, or injection we ll and its associated well site . For the purposes of the fugitive emissions standards at section I.1, well site also includes tank batteries collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water con densate from wells not located at the well site (e.g., centralized tank batteries).***E.O. 12866 R eview

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I - 8***E.O. 12866 Review

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United States Environmental Protection Agency Office of Air Quality Planning and Standards Sector Policies and Programs Division Research Triangle Park, NC Publication No. EPA - 453/P - 51 - 001 July, 2015