# Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution.

Background Technical Support Document for Proposed StandardsEPA

- 453/R

- 11

- 002 July 2011

Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas

Production, Transmission, and Distribution.

By: E C/R, Incorporated 501 Eastowne Dr, Suite 250 Chapel Hill , North Carolina 27514

Prepa red for: Bruce Moore , Project Officer Office of Air Quality Planning and Standards Sector Policies and Programs Division

Contract No. EP

- D

- 07

- 061 Work Order No. 4

- 06

U.S. Environmental Protection Agency Office of Air and Radiation Office of Air Quality Planning and Standards Research, Triangle Park, North Carolinaii DISCLAIMER This report has been reviewed by EPA’s Office of Air Quality Planning and Standards and has been approved for publication. Mention of trade names or commercial products is not intended to constitute endorsement or recommendation for use.iii FOREWORD
This background technical support document (TSD) provides information relevant to the proposal of New Source Performance Standards (NSPS) for limiting VOC emissions from the Oil and Natural Gas Sector. The proposed standards were developed according to section 111(b)(1)(B) under the Clean Air Act, which requires EPA to review and revise, is appropriate, NSPS standards. The NSPS review allows EPA to identify processes in the oi l and natural sector that are not regulated under the existing NSPS but may be appropriate to regulate under NSPS based on new information. This would include processes that emit the current regulated pollutants, VOC and SO 2 , as well as any additional poll utants that are identified. This document is the result of t h at review process. Chapter 1 provides introduction on NSPS regulatory authority. Chapter 2 presents an overview of the oil and natural gas sector. Chapter 3 discusses the entire NSPS review proces s undertaken for this review. Finally, Chapters 4

- 8 provide information on previously unreg ulated emissions sources. Each c hapter describes the emission source, the estimated emissions (on average) from these sources, potential control options identified t o reduce these emissions and the cost of each control option identified. In addition, secondary impacts are estimated and the rationale for the proposed NSPS for each emission source is provided.TABLE OF CONTENTS

1.0 NEW SOURCE PERFORMANCE BACKGROUND

................................ ................................ .................. 1

- 1 1.1 Statutory Authority

................................ ................................ ................................ ................................ .......... 1

- 1 1.2 History of Oil and Gas Source Category

................................ ................................ ................................ ......... 1

- 2 1.3 NSPS Review Process

................................ ................................ ................................ ................................ ...... 1

- 2

2.0 SECTOR DESCRIPTION

................................ ................................ ................................ .............................. 2

- 1

3.0 NEW SOURCE PERFORMANCE REVIEW PROCESS

................................ ................................ ........... 3

- 1 3.1 Evaluation of BSER for Existing NSPS

................................ ................................ ................................ ............ 3

- 1 3.1.1 BSER for VOC Emissions from Equipment Leaks at Natural Gas Processing Plants

............................. 3

- 1 3.1.2 BSER for SO2 Emissions from Sweetening Units at Natural Gas Processing Plants

.............................. 3

- 3 3.2 Additional Pollutants

................................ ................................ ................................ ................................ ....... 3

- 5 3.3 Additional Processes

................................ ................................ ................................ ................................ ........ 3

- 6

4.0 WELL COMPLETIONS AND RECOMPLETIONS

................................ ................................ ................. 4

- 1 4.1Process Description

................................ ................................ ................................ ................................ ............ 4

- 1 4.1.1 Oil and Gas Well Completions

................................ ................................ ................................ ................. 4

- 1 4.1.2 Oil and Gas Well Recompletions

................................ ................................ ................................ .............. 4

- 2 4.2.Emission Data and Emissions Factors

................................ ................................ ................................ .............. 4

- 3 4.2.1 Summary of Major Studies and Emission Factors

................................ ................................ .................... 4

- 3 4.2.2 Representative Completion and Recompletion Emissions

................................ ................................ ....... 4

- 6 4.3 Nationwide Emissions from New Sources

................................ ................................ ................................ ....... 4

- 8 4.3.1 Overview of Approach

................................ ................................ ................................ .............................. 4

- 8 4.3.2 Number of Completions and Recompletions

................................ ................................ ............................ 4

- 8 4.3.3 Level of Controlled Sources in Absence of Federal Regulation

................................ ............................. 4

- 10 4.3.4 Emission Estimates

................................ ................................ ................................ ................................ . 4

- 12 4.4 Control Techniques

................................ ................................ ................................ ................................ ........ 4

- 12 4.4.1 Potential Control Techniques

................................ ................................ ................................ ................... 4

- 12 4.4.2 Reduced Emission Completions and Recompletions

................................ ................................ ............... 4

- 14 4.4.2.1 Description

................................ ................................ ................................ ................................ ....... 4

- 14 4.4.2.2 Effectiveness

................................ ................................ ................................ ................................ .... 4

- 15 4.4.2.3 Cost Impacts

................................ ................................ ................................ ................................ ..... 4

- 15 4.4.2.4 Secondary Impacts

................................ ................................ ................................ ........................... 4

- 18 4.4.3Completion Combustion Devices

................................ ................................ ................................ ............. 4

- 18 4.4.3.1 Description

................................ ................................ ................................ ................................ ....... 4

- 18 4.4.3.2 Effectiveness

................................ ................................ ................................ ................................ .... 4

- 19 4.4.3.3 Cost Impacts

................................ ................................ ................................ ................................ ..... 4

- 19 4.4.3.4Secondary Impacts

................................ ................................ ................................ ............................. 4

- 20 4.5 Regulatory Options

................................ ................................ ................................ ................................ ........ 4

- 22 4.5.1 Evaluation of Regulatory Options

................................ ................................ ................................ ........... 4

- 24 4.5.2 Nationwide Impacts of Regulatory Options

................................ ................................ ............................ 4

- 27 4.5.2.1 Primary Environmental Impacts of Regulatory Options

................................ ................................ .. 4

- 27 4.5.2.2 Cost Impacts

................................ ................................ ................................ ................................ ..... 4

- 28 4.5.2.3 Secondary Impacts

................................ ................................ ................................ ........................... 4

- 30 4.6 References

................................ ................................ ................................ ................................ ....................... 4

- 325.0 PNEUMATIC CONTROLLERS

................................ ................................ ................................ ................. 5

- 1

5.1 Process Description

................................ ................................ ................................ ................................ ......... 5

- 1 5.2. Emission Data and Emissions Factors

................................ ................................ ................................ ............ 5

- 3 5.2.1 Summary of Major Studies and Emission Factors

................................ ................................ .................... 5

- 3 5.2.2 Representa tive Controller Emissions

................................ ................................ ................................ ........ 5

- 3 5.3 Nationwide Emissions from New Sources

................................ ................................ ................................ ....... 5

- 5 5.3.1 Overview of Approach

................................ ................................ ................................ .............................. 5

- 5 5.3.2 Population of Devices Installed Annually

................................ ................................ ................................ . 5

- 5 5 .3.3 Emission Estimates

................................ ................................ ................................ ................................ ... 5

- 9 5.4 Control Techniques

................................ ................................ ................................ ................................ .......... 5

- 9 5.4.1 Potential Control Techniques

................................ ................................ ................................ ..................... 5

- 9 5.4.2 Low Bleed Controllers

................................ ................................ ................................ ............................ 5

- 1 2 5.4.2.1 Emission Reduction Potential

................................ ................................ ................................ .......... 5

- 1 2 5.4.2.2 Effectiveness

................................ ................................ ................................ ................................ .... 5

- 1 2 5.4.2.3 Cost Impacts

................................ ................................ ................................ ................................ ..... 5

- 1 4 5.4.2.4 Secondary Impacts

................................ ................................ ................................ ........................... 5

- 1 6 5.4.3 Instrument Air Systems

................................ ................................ ................................ ........................... 5

- 1 6 5.4.3.1 D escription

................................ ................................ ................................ ................................ ....... 5

- 1 6 5.4.3.2 Effectiveness

................................ ................................ ................................ ................................ .... 5

- 1 8 5.4.3.3 Cost Impacts

................................ ................................ ................................ ................................ ..... 5

- 19 5.4.3.4 Secondary Impacts

................................ ................................ ................................ ........................... 5

- 2 2 5.5 Regulatory Option

................................ ................................ ................................ ................................ .......... 5

- 22 5.5.1 Evaluation of Regulatory Options

................................ ................................ ................................ ........... 5

- 2 2 5.5.2 Nationwide Impacts of Regulatory Options

................................ ................................ ............................ 5

- 2 4 5.6 References

................................ ................................ ................................ ................................ ....................... 5

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6.0 COMPRESSORS

................................ ................................ ................................ ................................ ........... 6

- 1 6.1 Process Description

................................ ................................ ................................ ................................ .......... 6

- 1 6.1.1 Reciprocating Compressors

................................ ................................ ................................ ...................... 6

- 1 6.1.2 Centrifugal Compressors

................................ ................................ ................................ .......................... 6

- 2 6.2. Emission Data and Emissions Factors

................................ ................................ ................................ ............ 6

- 2 6.2.1 Summary of Major Studies and Emission Factors

................................ ................................ .................... 6

- 2 6.2.2 Representative Reciprocating and Centrifugal Compressor Emissions

................................ .................... 6

- 2 6.3 Nationwide Emissions from New Sources

................................ ................................ ................................ ....... 6

- 6 6.3.1 Overview of Approach

................................ ................................ ................................ .............................. 6

- 6 6.3.2 Activity Data for Reciprocating Compressors

................................ ................................ .......................... 6

- 6 6.3.2.1 Wellhead Reciprocating Compressors

................................ ................................ ............................... 6

- 6 6.3.2.2 Gathering and Boosting Reciprocating Compressors

................................ ................................ ........ 6

- 8 6.3.2.3 Processing Reciprocating Compressors

................................ ................................ ............................. 6

- 8 6.3.2 .4 T ransmission and Storage Reciprocating Compressors

................................ ................................ ..... 6

- 9 6.3.3 Level of Controlled Sources in Absence of Federal Regulation

................................ ............................... 6

- 9 6.3.4 Emission Estimates

................................ ................................ ................................ ................................ ... 6

- 9 6.4 Control Techniques

................................ ................................ ................................ ................................ ........ 6

- 11 6.4.1 Potential Control Techniques

................................ ................................ ................................ .................. 6

- 11 6.4.2 Reciprocating Compressor Rod Packing Replacement

................................ ................................ ........... 6

- 1 2 6.4.2.1 Description

................................ ................................ ................................ ................................ ....... 6

- 1 2 6.4.2.2 Effectiveness

................................ ................................ ................................ ................................ .... 6

- 1 2 6.4.2.3 Cost Impacts

................................ ................................ ................................ ................................ ..... 6

- 1 6 6.4.2.4 Secondary Impacts

................................ ................................ ................................ ........................... 6

- 18 6.4.3 Centrifugal Compressor Dry Seals

................................ ................................ ................................ ......... 6

- 186.4.3.1 Description

................................ ................................ ................................ ................................ ....... 6

- 18

6.4.3.2 Effectiveness

................................ ................................ ................................ ................................ .... 6

- 19 6.4.3.3 Cost Impacts

................................ ................................ ................................ ................................ ..... 6

- 19 6.4.3.4 Secondary Impacts

................................ ................................ ................................ ........................... 6

- 2 1 6.4.4 Centrifugal Compressor Wet Seals with a Flare

................................ ................................ ..................... 6

- 21 6.4.4 .1 Description

................................ ................................ ................................ ................................ ....... 6

- 21 6.4.4 .2 Effectiveness

................................ ................................ ................................ ................................ .... 6

- 23 6.4.4 .3 Cost Impacts

................................ ................................ ................................ ................................ ..... 6

- 23 6.4.4.4 Secondary Impacts

................................ ................................ ................................ ........................... 6

- 23 6.5 Regulatory Options

................................ ................................ ................................ ................................ ........ 6

- 2 3 6.5.1 Evaluation of Regulatory Options

................................ ................................ ................................ ........... 6

- 2 7 6.5.2 Nationwide Impacts of Regulatory Options

................................ ................................ ............................ 6

- 2 8 6.6 References

................................ ................................ ................................ ................................ ....................... 6

- 31

7.0 STORAGE VESSELS

................................ ................................ ................................ ................................ ... 7

- 1 7.1 Process Description

................................ ................................ ................................ ................................ .......... 7

- 2 7.2. Emission Data

................................ ................................ ................................ ................................ ................. 7

- 2 7.2.1 Summary of Major Studies and Emission Factors

................................ ................................ .................... 7

- 2 7.2.2 Representative Storage Vessel Emissions

................................ ................................ ................................ . 7

- 2 7.2.2 .1 Model Condensate Tank Batteries

................................ ................................ ................................ ..... 7

- 2 7.2.2 .2 Model Crude Oil Tank Batteries

................................ ................................ ................................ ........ 7

- 4 7.2.2 .3 VOC Emissions from Model Condensate and Crude Oil Storage Vessels

................................ ........ 7

- 4 7.3 Nationwide Emissions from New Sources

................................ ................................ ................................ ..... 7

- 10 7.3.1 Overview of Approach

................................ ................................ ................................ ............................ 7

- 10 7.3.2 Number of New Storage Vessels Expected to be Constructed or Reconstructed

................................ .. 7

- 10 7.3.3 Level of Controlled Sources in Absence of Federal Regulation

................................ ............................. 7

- 10 7.3.4 Nationwide Emission Estimates for New or Modified Storage Vessels

................................ ................. 7

- 12 7.4 Control Techniques

................................ ................................ ................................ ................................ ........ 7

- 12 7.4.1 Potential Control Techniques

................................ ................................ ................................ .................. 7

- 12 7.4.2 Vapor Recovery Units

................................ ................................ ................................ ............................. 7

- 12 7.4.2.1 Description

................................ ................................ ................................ ................................ ....... 7

- 12 7.4.2.2 Effectiveness

................................ ................................ ................................ ................................ .... 7

- 13 7.4.2.3 Cost Impacts

................................ ................................ ................................ ................................ ..... 7

- 13 7.4.2.4 Secondary Impacts

................................ ................................ ................................ ........................... 7

- 13 7.4.3 Combustors

................................ ................................ ................................ ................................ ............. 7

- 15 7.4.3.1 Description and Effectiveness

................................ ................................ ................................ .......... 7

- 15 7.4.3.2 Cost Impacts

................................ ................................ ................................ ................................ ..... 7

- 15 7.4.3.3 Secondary Impacts

................................ ................................ ................................ ........................... 7

- 15 7.5 Regulatory Options

................................ ................................ ................................ ................................ ........ 7

- 18 7.5.1 Evaluation of Regulatory Options

................................ ................................ ................................ ........... 7

- 18 7.5.2 Nationwide Impacts of Regulatory Options

................................ ................................ ............................ 7

- 22 7.5.3 Primary Environmental Impacts of Regulatory Options Impacts

................................ ........................... 7

- 22 7.5.4 Cost Impacts

................................ ................................ ................................ ................................ ............ 7

- 24 7.6 References

................................ ................................ ................................ ................................ ....................... 7

- 26

8.0 EQUIPMENT LEAKS

................................ ................................ ................................ ................................ . 8

- 1 8.1 Process Description

................................ ................................ ................................ ................................ .......... 8

- 1 8.2. Emission Data and Emissions Factors

................................ ................................ ................................ ............ 8

- 1 8.2.1 Summary of Major Studies a nd Emission Factors

................................ ................................ .................... 8

- 1 8.2.2 Model Plant

................................ ................................ ................................ ................................ ............... 8

- 28.2.2 .1 Oil and Natural Gas Production

................................ ................................ ................................ ......... 8

- 2

8.2.2 .2 Oil and Natural Gas Processing

................................ ................................ ................................ ......... 8

- 9 8.2.2 .3 Natural Gas Transmission

................................ ................................ ................................ .................. 8

- 9 8.3 Nationwide Emissions from New Sources

................................ ................................ ................................ ....... 8

- 9 8.3.1 Overview of Approach

................................ ................................ ................................ .............................. 8

- 9 8.3.2 Activity Data

................................ ................................ ................................ ................................ ........... 8

- 13 8.3.2.1 Well Pads

................................ ................................ ................................ ................................ ......... 8

- 13 8.3.2.2 Gathering and Boosting

................................ ................................ ................................ ................... 8

- 13 8.3.2.3 Processing Facilties

................................ ................................ ................................ .......................... 8

- 16 8 .3.2.4 Transmission and Storage Facilties

................................ ................................ ................................ .. 8

- 16 8.3.4 Emission Estimates

................................ ................................ ................................ ................................ . 8

- 16 8.4 Control Techniques

................................ ................................ ................................ ................................ ........ 8

- 18 8.4.1 Potential Control Techniques

................................ ................................ ................................ .................. 8

- 18 8.4.2 Subpart VVa LDAR Program

................................ ................................ ................................ ............... 8

- 21 8.4.2.1 Description

................................ ................................ ................................ ................................ ....... 8

- 21 8.4.2.2 Effectiveness

................................ ................................ ................................ ................................ .... 8

- 21 8.4.2.3 Cost Impacts

................................ ................................ ................................ ................................ ..... 8

- 23 8.4.2.4 Secondary Impacts

................................ ................................ ................................ ........................... 8

- 26 8.4.3 LDAR with Optical Gas Imaging

................................ ................................ ................................ ........... 8

- 31 8.4.3.1 Description

................................ ................................ ................................ ................................ ....... 8

- 31 8.4.3.2 Effectiveness

................................ ................................ ................................ ................................ .... 8

- 31 8.4.3.3 Cost Impacts

................................ ................................ ................................ ................................ ..... 8

- 31 8.4.3.4 Secondary Impacts

................................ ................................ ................................ ........................... 8

- 34 8 .4.4 Modified Alternative Work Practice with Optical Gas Imaging

................................ ............................. 8

- 34 8.4 .4 .1 Description

................................ ................................ ................................ ................................ ....... 8

- 34 8.4.4 .2 Effectiveness

................................ ................................ ................................ ................................ .... 8

- 34 8.4.4 .3 Cost Impacts

................................ ................................ ................................ ................................ ..... 8

- 35 8.4.4.4 Secondary Impacts

................................ ................................ ................................ ........................... 8

- 35 8.5 Regulatory Options

................................ ................................ ................................ ................................ ........ 8

- 37 8.5.1 Evaluation of Regulatory Options for Equipment Leaks

................................ ................................ ........ 8

- 37 8.5 .1 .1 Well Pads

................................ ................................ ................................ ................................ ......... 8

- 37 8.5 .1 .2 Gathering and Boosting

................................ ................................ ................................ ................... 8

- 38 8.5 .1 .3 Processing Facilties

................................ ................................ ................................ .......................... 8

- 39 8 .5 .1 .4 Transmission and Storage Facilties

................................ ................................ ................................ .. 8

- 39 8.5.2 Nationwide Impacts of Regulatory Options

................................ ................................ ............................ 8

- 40 8.6 References

................................ ................................ ................................ ................................ ....................... 8

- 42

APPENDIX A1

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1 .0 NEW SOURCE PERFORMAN CE STANDARD BACKGROU ND Standards of performance for new stationary sources are established under section 111 of the Clean Air Act (42 U.S .C. 7411), as amended in 1977. Section 111 directs the Administrator to establish standards of performance for any category of new stationary sources of air pollution which “...causes or contributes significantly to air pollution which may reasonably be anti cipated to endan ger public health or welfare.” This technical support document (TSD) supports the proposed standards, which would control volatile organic compounds (VOC) and sulfur dioxide (SO 2 ) emissions from the oil and natural gas sector.

1.1 Statutory Authority
Section 111 of the Clean Air Act (CAA) requires the E nvironmental Protection Agency Administrator to list categories of stationary sources, if such sources cause or contribute significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. The EPA must then issue performance standards for such source categories. A performance standard reflects the degree of emission limitation achievable through the application of the “best system of emission reduction” (B SER) which the EPA determines has been adequately demonstrated. The EPA may consider certain costs and nonair quality health and environmental impact and energy requirements when establishing performance standards. Whereas CAA section 112 standards are iss ued for existing and new stationary sources, standards of performance are issued for new and modified stationary sources. These standards are referred to as new source performance standards (NSPS). The EPA has the authority to define the source categories, determine the pollutants for which standards should be developed, identify the facilities within each source category to be covered and set the emission level of the standards.
CAA section 111(b)(1)(B) requires the EPA to “at least every 8 years review a nd, if appropriate, revise” performance standards unless the “Administrator determines that such review is not appropriate in light of readily available information on the efficacy” of the standard. When conducting a review of an existing performance stand ard, the EPA has discretion to revise that standard to add emission limits for pollutants or emission sources not currently regulated for that source category.
In setting or revising a performance standard, CAA section 111(a)(1) provides that performance

s tandards are to “reflect the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any1

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non

- air quality health and environmental impact a nd energy requirements) the Administrator determines has been adequately demonstrated.” This level of control is referred to as the best system of emission reduction (BSER). In determining BSER, a technology review is conducted that identifies what emissio n reduction systems exist and how much the identified systems reduce air pollution in practice. F or each control system identified, the costs and secondary air benefits (or disbenefits) resulting from energy requirements and non

- air quality impacts such as solid waste generation are also evaluated. This analysis determines BSER. The resultant standard is usually a numerical emissions limit, expressed as a performance level (i.e., a rate

- based standard or percent control), that reflects the BSER. Although su ch 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 p erformance. Typically, sources remain free to elect whatever control measures that they choose to meet the emission limits. Upon promulgation, a NSPS becomes a national standard to which all new, modified or reconstructed sources must comply.

1. 2 History o f Oil and Natural Gas Source Category
In 1979, the EPA listed crude oil and natural gas production on its priority list of source categories for promulgation of NSPS (44 FR 49222, August 21, 1979). On June 24, 1985 (50 FR 26122), the EPA promulgated a NSPS for the source category that addressed volatile organic compound (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 sulfur dioxide (SO 2 ) emissions from natural gas processing plants (40 CFR part 60, subpart LLL). Other than natural gas processing plants, EPA has not previously set NSPS for a variety of oil and natural gas operations. These NSPS are relatively narrow in scope as they address emissions only at natural gas processing plants. Specifically, subpart KKK addresses VOC emissions from leaking equipment at onshore natural gas processing plants, and subpa rt LLL addresses SO 2 emissions from natural gas processing plants.

1. 3 NSPS Review Process Overview
CAA section 111(b)(1)(B) requires EPA to review and revise, i f appropriate, NSPS standards. First, the existing NSPS w ere evaluated to determine whether it reflect s BSER for the emission affected sources. This review was conducted by examining control technologies currently in use and assessing whether1

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these technologies represent advances in emission reduction techniques compared to the technologies upon whi ch the existing NSPS are based. For each new control technology identified, the potential emission reductions, costs, secondary air benefits (or disbenefits) resulting from energy requirements and non

- air quality impacts s uch as solid w aste generation are evaluated. The second step is evaluating whether there are additional pollutants emitted by facilities in the oil and natural gas sector that contribute significantly to air pollution and may reasonably be anticipated to endanger public health or welfare

. The final review step is to identify additional processes in the oil and natural gas sector that are not covered under the existing NSPS but may be appropriate to develop NSPS based on new information

. This would include processes that emit the current reg ulated pollutants, VOC and SO 2 , as well as any additional pollutants that are identified. The entire review process is described in Chapter 3.2

- 1 2 .0 OIL AND NATURAL GAS SECTOR OVERVIEW
The oil and natural gas sector includes operations involved in the extraction and production of oil and natural gas, as well as the processing, transmission and distribution of natural gas. Specifically for oil, the sector includes all operations from the well to the point of custody transfer at a petroleum refinery. For natural gas, the sector includes all operations from the well to the customer. The oil and natural gas operations can generally be separated into four segments: (1) oil and natural gas prod uction, (2) natural gas processing, (3) natural gas transmission and (4) natural gas distribution. Each of these segments is briefly discussed below.
Oil and natural gas production includes both onshore and offshore operations. Production operations inclu de the wells and all related processes used in the extraction, production, recovery, lifting, stabilization, separation or treating of oil and/or natural gas (including condensate). Production components may include, but are not limited to, wells and relat ed casing head, tubing head and “Christmas tree” piping, as well as pumps, compressors, heater treaters, separators, storage vessels, pneumatic devices and dehydrators. Production operations also include well drilling, completion and recompletion processes ; which includes all the portable non

- self

- propelled apparatus associated with those operations. Production sites include not only the “pads” where the wells are located, but also
include stand

- alone sites where oil, condensate, produced water and gas from several wells may be separated, stored and treated. The production sector also includes the low pressure, small diameter, gathering pipelines and related components that collect and transport the oil, gas and other materials and wastes from the wells to t he refineries or natural gas processing plants. None of the operations upstream of the natural gas processing plant (i.e. from the well to the natural gas processing plant ) are covered by the existing NSPS. Offshore oil and natural gas production occurs on platform structures that house equipment to extract oil and gas from the ocean or lake floor and that process and/or transfer the oil and gas to storage, transport vessels or onshore. Offshore production can also include secondary platform

structures conn ected to the platform structure, storage tanks associated with the platform structure and floating production and offloading equipment.
There are three basic types of wells: Oil wells, gas wells and associated gas wells. Oil wells can have “associated” nat ural gas that is separated and processed or the crude oil can be the only product processed. Once the crude oil is separated from the water and other impurities, it is essentially ready to be transported to the refinery via truck, railcar or pipeline. T he oil refinery sector is considered2

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separately from the oil and natural gas sector. Therefore, at the point of custody transfer at the refinery, the oil leaves the oil and natural gas sector and enters the petroleum refining sector.
Natural gas is primarily made up of methane. However, whether natural gas is associated gas from oil wells or non

- associated gas from gas or condensate wells, it commonly exists in mixtures with other hydrocarbons. These hydrocarbons are often referred to as natural gas liquids (N GL). They are sold separately and have a variety of different uses. The raw natural gas often contains water vapor, hydrogen sulfide (H 2 S), carbon dioxide (CO 2 ), helium, nitrogen and other compounds. Natural gas processing consists of separating certain hy drocarbons and fluids from the natural gas to produced “pipeline quality” dry natural gas. While some of the processing can be accomplished in the production segment, the complete processing of natural gas takes place in the natural gas processing segment. Natural gas processing operations separate and recover natural gas liquids or other non

- methane gases and liquids from a stream of produced natural gas through components performing one or more of the following processes: Oil and condensate separation, wa ter removal, separation of natural gas liquids, sulfur and CO 2 removal, fractionation of natural gas liquid and other processes, such as the capture of CO 2 separated from natural gas streams for delivery outside the facility. Natural gas processing plants are the only operations covered by the existing NSPS.
The pipeline quality natural gas leaves the processing segment and enters the transmission segment. Pipelines in the natural gas transmission segment can be interstate pipelines that carry natural gas across state boundaries or intrastate pipelines, which transport the gas within a single state. While interstate pipelines may be of a larger diameter and operated at a higher pressure, the basic components are the same. To ensure that the natural gas flow ing through any pipeline remains pressurized, compression of the gas is required periodically along the pipeline. This is accomplished by compressor stations usually placed between 40 and 100 mile intervals along the pipeline. At a compressor station, the natural gas enters the station, where it is compressed by reciprocating or centrifugal compressors.
In addition to the pipelines and compressor stations, the natural gas transmission segment includes underground storage facilities. Underground natural gas storage includes subsurface storage, which typically consists of depleted gas or oil reservoirs and salt dome caverns used for storing natural gas. One purpose of this storage is for load balancing (equalizing the receipt and delivery of natural gas). At

a n underground storage site, there are typically other processes, including compression, dehydration and flow measurement.2

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The distribution segment is the final step in delivering natural gas to customers. The natural gas enters the distribution segment fro m delivery points located on interstate and intrastate transmission pipelines to business and household customers. The delivery point where the natural gas leaves the transmission segment and enters the distribution segment is often called the “citygate.” Typically, utilities take ownership of the gas at the citygate. Natural gas distribution systems consist of thousands of miles of piping, including mains and service pipelines to the customers. Distribution systems sometimes have compressor stations, altho ugh they are considerably smaller than transmission compressor stations. Distribution systems include metering stations, which allow distribution companies to monitor the natural gas in the system. Essentially, these metering stations measure the flow of g as and allow distribution companies to track natural gas as it flows through the system.
Emissions can occur from a variety of processes and points throughout the oil and natural gas sector. Primarily, these emissions are organic compounds such as methane, ethane, VOC and organic hazardous air pollutants ( HAP ) . The most common organic HAP are n

- hexane and BTEX compounds (benzene, toluene, ethylbenzene and xylenes). Hydrogen sulfide and SO 2 are emitted from production and processing op erations that handle an d treat sour gas i

In addition, there are significant emissions associated with the reciprocating internal combustion engines and combustion turbines that power compressors throughout the oil and natural gas sector. However, emissions from internal combust ion engines and combustion turbines are covered by regulations specific to engines and turbines and, thus, are not addressed in this action.

i Sour gas is defined as natural gas with a maximum H 2 S content of 0.25 gr/100 scf (4ppmv) along with the presence of CO 2Figure 2

- 1. Oil and Natural Gas Operations

2

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- 1 3 .0 N EW SOURCE PERFORMANCE S TANDARD REVIEW As discussed in section 1.2, there are two NSPS that impact the oil and natural gas sector: (1) the NSPS for equipment leaks of VOC at natural gas processing plants (subpart KKK) and (2) the NSPS for SO 2 emissions from sweetening units located at natural gas p rocessing plants (subpart LLL). Because they only address emissions from natural gas processing plants, these NSPS are relatively narrow in scope.

Section 111(b)(1) of the CAA requires the EPA to review and revise, i f appropriate, NSPS standards. This review process c onsisted of the following steps:
1. Evaluation of the existing NSPS to determine whether they continue to reflect the BSER for t he emi ssion sources that they address;
2. Evaluation of whether there were additional pollutants emitted by facilities in the oil and natural gas sector that warrant regulation and for which there is adequate information to promulgate standards of performan ce ; and 3. Identification of additional processes in the oil and natural gas sector for which it would be appropriate to develop performance standards, including processes that emit the currently regulated pollutants as well as any additional pollutants identif ied in step two. The following sections detail each of these steps.

3 .1 Evaluation of BSER for Existing NSPS

Consistent with the obligations under CAA section 111(b), control options reflected in the current NSPS for the Oil and Natural Gas source category were evaluated in order to distinguish if these options still represent BSER. To evaluate the BSER options for equipment leaks the following was reviewed: EPA’s

current leak detection and repair ( LDAR ) programs, the Reasonably Available Control Technology (RACT)/Best Available Control Technology (BACT)/Lowest Achievable Emission Rate (LAER) Clearinghouse (RBLC) database, and emerging technologies that have been identified by partners in the Natural Gas STAR program. 1

3.1.1 BSER for VOC Emissions from Equipment Leaks at Natural Gas Processing Plants
The current NSPS for equipment leaks of VOC at natural gas processing plants (40 CFR part 60, subpart KKK) requires compliance with spe cific provisions of 40 CFR part 60, subpart VV, which is a LDAR
program, based on the use of EPA Method 21 to identify equipment leaks. In addition to the subpart VV requirements, the LDAR requirements in 40 CFR part 60, subpart VVa were also reviewed . This LDAR3

- 2

program is considered to be more stringent than the subpart VV re quirements, because it has lower component leak threshold definitions and more frequent monitoring, in comparison to the subpart VV program. Furthermore, subpart VVa requires monitoring of connectors, while subpart VV does not. O ptions based on optical gas imaging were also reviewed

.

T he currently required LDAR program for natural gas processing plants (40 CFR part 60, subpart KKK) is based on EPA Method 21, which requires the use of an organic vapor analyzer to monitor components and to measure the concent ration of the emissions in identifying leaks. Although there have been advancements in the use of optical gas imaging to detect leaks from these same types of components,

t hese instruments do not yet p rovide a direct measure of leak concentrations. The ins truments instead provide a measure of a leak relative to an instrument specific calibration point. Since the promulgation of 40 CFR part 60, subpart KKK (which requires Method 21 leak measurement monthly), the EPA has updated the 40 CFR part 60 General Pro visions to allow the use of advanced leak detection tools, such as optical gas imaging and ultrasound equipment as an alternative to the LDAR protocol based on Method 21 leak measurements (see 40 CFR 60.18(g)). The alternative work practice allowing use of these advanced technologies includes a provision for conducting a Method 21

- based LDAR check of the regulated equipment annually to verify good performance.

I n considering BSER for VOC equipment leaks at natural gas processing plants , four options were

ev aluated . One option evaluated consists of changing from a 40 CFR part 60, subpart VV

- level program, which is what 40 CFR part 60, subpart KKK currently requires, to a 40 CFR part 60, subpart VVa program, which applies to new synthetic organic chemical plan ts after 2006. Subpart VVa lowers the leak definition for valves from 10,000 parts per million (ppm) to 500 ppm, and requires the monitoring of connectors. In our analysis of these impacts, it was estimated that, for a typical natural gas processing plant, the incremental cost effectiveness of changing from the current subpart VV

- level program to a subpart VVa

- level program using Method 21 is $3,352 per ton of VOC reduction.

In evaluating 40 CFR part 60, subpart VVa

- level LDAR at processing plants, the indi vidual types of components (valves, connectors, pressure relief devices and open

- ended lines) were also analyzed separately to determine cost effectiveness for individual components. Detailed discussions of these
comp onent

- by

- component analyses are provide d in Chapter 8 . Cost effectiveness ranged from $144 per ton of VOC (for valves) to $4,360 per ton of VOC (for connectors), with no change in requirements for pressure relief devices and open

- ended lines.3

- 3

Another option evaluated for gas processing plants w as the use of optical gas imaging combined with an annual EPA Method 21 check (i.e., the alternative work practice for monitoring equipment for leaks at 40 CFR 60.18(g)). It was previously determined that the VOC reduction achieved by this combination of

o ptical gas imaging and Method 21 would be equivalent to reductions achieved by the 40 CFR part 60, subpart VVa

- level program. Based on the emission reduction level , the cost effectiveness of this option was estimated to be $6,462 per ton of VOC reduction. This analysis wa s based on the facility purchasing an optical gas imaging system costing $85,000. However, at least one manufacturer was identified that rents the optical gas imaging systems. That manufacturer rents the optical gas imaging system for $3,95 0 per week. Using this rental cost in place of the purchase cost, the VOC cost effectiveness of the monthly optical gas imaging combined with annual Method 21 inspection visits is $4,638 per ton of
VOC reduction. i

A third option evaluated consisted of mon thly optical gas imaging without an annual Method 21 check.
T he annual cost of the monthly optical gas imaging LDAR program was estimated to be $76,581 based

on camera purchase, or $51,999 based on camera rental. However, it is not possible to quantify the VOC emission reductions achieved by an optical imaging program alone, therefore the cost effectiveness of this option could not be determined. Finally, a fourth option was evaluated that was similar to the third option, except that the optical gas imaging would be performed annually rather than monthly. For this option, the annual cost was estimated to be $43,851, based on camera purchase, or $18,479, based on
camera rental.

Because the cost effectiveness of options 3 and 4 could not be estimated , these options could not be identified as BSER for reducing VOC leaks at gas processing plants. Because options 1 and 2 achieve equivalent VOC reduction and are both cost effective, both options 1 and 2 reflect BSER for LDAR for natural gas processing plants. As mentioned above, option 1 is the LDAR in 40 CFR part 60, subpart VVa and option 2 is the alternative work practice at 40 CFR 60.18(g) and is already available to use as an alternative to subpar t VVa LDAR.

3.1.2 BSER for SO 2 Emissions from Sweetening Units at Natural Gas Processing Plants
For 40 CFR part 60, subpart LLL, control systems for SO 2 emissions from sweetening units located at natural gas processing plants were evaluated , including tho se followed by a sulfur recovery unit. Subpart

i Because optical gas imaging is used to view multiple pieces of equipment at a facility during one leak survey, options involving imaging are not amenable to a component by component analysis.3

- 4

LLL provides specific standards for SO 2 emission reduction efficiency, on the basis of sulfur feed rate and the sulfur content of the natural gas.
According to available literature, the most widely used proces s for converting H 2 S in acid gases (i.e.,
H 2 S and CO 2 ) separated from natural gas by a sweetening process (such as amine treating) into elemental sulfur is the Claus process. Sulfur recovery efficiencies are higher with higher concentrations of H 2 S in the feed stream due to the thermodynamic equilibrium limitation of the Claus process. The Claus sulfur recovery unit produces elemental sulfur from H 2 S in a series of catalytic stages, recovering up to 97

- percent recovery of the sulfur from the acid gas from t he sweetening process. Further, sulfur recovery is accomplished by making process modifications or by employing a tail gas treatment process to convert the unconverted sulfur compounds from the Claus unit.

In addition, process modifications and tail gas tr eatment options were also evaluated at the time 40 CFR part 60, subpart LLL was proposed

. ii As explained in the preamble to the proposed subpart LLL, control through sulfur recovery with tail gas treatment may not always be cost effective, depending on sulf ur feed rate and inlet H 2 S concentrations. Therefore, other methods of increasing sulfur recovery via process modifications were evaluated.
As shown in the original evaluation for the proposed subpart LLL , the performance capabilities and costs of each of these technologies are highly dependent on the ratio of H 2 S and CO 2 in the gas stream and the total quantity of sulfur in the gas stream being treated. The most effective means of control was selected as BSER for the different stream characteristics. As a result, separate emissions limitations were developed in the form o f equations that calculate the required initial and continuous emission reduction efficiency for each plant. The equations were based on the design performance capabilities of the technologies selected as BSER relative to the gas stream characteristics. iii T he emission limit for sulfur feed rates at or below 5 long tons per day, regardless of H 2 S content, was 79 percent. For facilities with sulfur feed rates above 5 long tons per day, the emission limits ranged from 79 percent at an H 2 S content below 10 perce nt to 99.8 percent for H 2 S contents at or above 50 percent.

To review these emission limitations, a search was performed of the RBLC data base 1 and state regulat ions. No S tate regulations were identified that included emission limitations more stringent than 40 CFR part 60, subpart LLL. However, two entries in the RBLC database were identified having SO 2

ii 49 FR 2656, 2659

- 2660 (1984). iii 49 FR 2656, 2663

- 2664 (1984).3

- 5

emission reductions of 99.9 percent. One entry is for a faci lity in Bakersfield, California, with a 90 long ton per day sulfur recovery unit followed by an amine

- based tailgas treating unit. The second entry is for a facility in Coden, Alabama, with a sulfur recovery unit with a feed rate of 280 long tons of sulfur per day, followed by selective catalytic reduction and a tail gas incinerator. However, neither of these entries contained information regarding the H 2 S contents of the feed stream. Because the sulfur recovery efficiency of these large sized plants was gr eater than 99.8 percent, the original data was reevaluated

. Based on the ava ilable cost information, a 99.9 percent efficiency is cost effective for facilities with a sulfur feed rate greater than 5 long tons per day and H 2 S content equal to or greater tha n 50 percent. Based on this review, the maximum initial and continuous efficiency for facilities with a sulfur feed rate greater than 5 long tons per day and a H 2 S content equal to or greater than 50 percent is raised to 99.9 percent.

The search of the RB LC database did not uncover information regarding costs and achievable emission reductions to suggest that the emission limitations for facilities with a sulfur feed rate less than 5 long tons per day or H 2 S content less than 50 percent should be modified. Therefore, there were not any identifiable changes to the emissions limitations for facilities with sulfur feed rate and H 2 S content less than 5 long tons per day and 50 percent, respectively

. 1

3.2 Additional Pollutants

The two current NSPS for the Oil and Natural Gas source category address emissions of VOC and SO 2 . In addition to these pollutants, sources in this source category also emit a variety of other pollutants,

most notably, air toxics. However , there are NESHAP that address air toxics from the oil and natural gas sector, specifically 40 CFR subpart HH and 40 CFR subpart HHH.
In addition, processes in the Oil and Natural Gas source category emit significant amounts of methane. The 1990

- 2009 U.S. GHG Inventory estimates 2009 methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries) to be 251.55 MMtCO2e (million metric tons of CO2

- equiva lents (CO2e)). iv The emissions estimated from well completions and recompletions exclude a significant number of wells completed in tight sand plays, such as the Marcellus, due to availability of data when the 2009 Inventory was developed. The estimate in t his proposal includes an adjustment for tight sand plays (being considered as a planned improvement in development of the 2010 Inventory).

iv U.S. EPA. Inventory of U. S. Greenhouse Gas Inventory and Sinks. 1990

- 2009. http://www.epa.gov/climatechange/emissions/downloads10/US

- GHGInventory 2010_ExecutiveSummary.pdf3

- 6

This adjustment would i ncrease the 2009 Inventory estimate by 76.74 MMtCO2e. The total methane emissions from Petrole um and Natural Gas Systems, based on the 2009 Inventory, adjusted for tight sand plays and the Marcell us, is 328.29 MMtCO2e.
Although this proposed rule does not include standards for regulating the GHG emissions discussed above, EPA continue s to assess these significant emissions and evaluate appropriate actions for addressing these concerns. Because many of the proposed requirements for control of VOC emissions also control methane emissions as a co

- benefit, the proposed VOC standards would also achieve significant reduction of methane emissions.

Significant emissions of oxides of nitrogen (NO x ) also occur at oil and natural gas sites due to the combustion of natural gas in reciprocating engines and combustion turbines used to drive the compressors that move natural gas through the system, and from combustion of natural gas in heaters and boilers. While these engines, turbines, heaters and boilers are co

- located with processes in the oil and natural gas sector, they are not in the Oil and Natural Gas sour ce category and are not being addressed in this action. The NO x emissions from engines and turbines are covered by the Standards of Performance for Stationary Spark Internal Combustion Engines (40 CFR part 60, subpart JJJJ) and Standards of Performance for Stationary Combustion Turbines (40 CFR part 60, subpart KKKK), respectively.

An additional source of NO x emissions would be pit flaring of VOC emissions from well completions. As discussed in Chapter 4 Well completions , pit flaring is one option identifie d for controlling VOC emissions. Because there is no way of directly measuring the NO x produced, nor is there any way of applying controls other than minimizing flaring, flaring would only be required for limited conditions.

3 .3 Additional Processes

The current NSPS only cover emissions of VOC and SO 2 from one type of facility in the oil and natural gas sector, which is the natural gas processing plant. This is the only type of facility in the Oil and Natural Gas source category where SO 2 is expected to b e emitted directly; a lthough H 2 S contained in
sour gas v forms SO 2 as a product of oxidation when oxidized in the atmosphere or combusted in boilers and heaters in the field. These field boilers and heaters are not part of the Oil and Natural Gas source

cat egory and are generally too small to be regulated by the NSPS covering boilers (i.e., they have a heat

v Sour gas is defined as natural gas with a maximum H 2 S content of 0.25 gr/10 0 scf (4ppmv) along with the presence of CO 2 .3

- 7

input of less than 10 million British Thermal Units per hour). They may, however, be included in future rulemakings.
In addition to VOC emissions from g as processing plants, there are numerous sources of VOC throughout the oil and natural gas sector that are not addressed by the current NSPS. P ursuant to CAA section 111(b), a modification of the listed category will now include all segments of the oil and natural gas industry for regulation. In addition, VOC standards will now cover additional processes at oil and natural gas operations. These include NSPS for VOC from gas well completions and recompletions , pneumatic controllers, compressors and storage v essels. In addition, produced water ponds may also be a potentially significant source of emissions, but there is very limited information available regarding these emissions. Therefore, no options could be evaluated at this time. The remainder of this doc ument presents the evaluation for each of the new processes to be included in the NSPS.

3.4 References 1 Memorandum to Bruce Moore from Brad Nelson and Phil Norwood. Crude Oil and Natural Gas Production NSPS Technology Reviews. EC/R Incorporated. July 28, 2011.4

- 1 4.0 WELL COMPLETIONS AND RECOMPLETION S
In the oil and natural gas sector, well completions and recompletions contain multi

- phase processes with various sources of emissions. One specific emission source during completion and recompletion activities is the venting of natural gas to t he atmosphere during flowback. Flowback emissions are short

term in nature and occur as a specific event during completion of a new well or during recompletion activities that involve re

- drilling or re

- fracturing an existing well

. This chapter describes completions and recompletions , and provides estimates for representative wells in addition to nationwide emissions

. Control techniques employed to re duce emissions from flowback gas venting during completions and recompletions are presented, along with costs, emission reductions, and secondary impacts

. Finally, this chapter discusses considerations in developing regulatory alternatives for reducing flo wback emissions during completions and recompletions

.

4.1 Process Description

4.1.1 Oil and Gas Well Completions
All oil and natural gas wells must be “completed” after initial drilling in preparation for production

. Oil and natural gas completion activit ies not only will vary across formations, but can vary between wells in the same formation

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

. Conventional gas reservoirs have well defined formations with high resource allocation in permeable and porous formations, and wells in conventional gas reservoirs have generally not required stimulation during production

. Unconventional gas reservoirs are more dispersed and found in lower concentrations and may require stimulation (such as hydraulic fracturing) to extract gas. 1

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

. These steps include inserting and cementing

- in well casing, perforating the casing at one or more producing horizons, and often hydraulically fracturing one or more zones in the reservoir to stimulate production

. Surface components, including wellheads, pumps, dehydrators, separators, tanks, and gathering l ines are installed as necessary for production to begin

. The flowback stage of a well completion is highly variable but typically lasts between 3 and 10 days for the average well. 24

- 2

Developmental wells are drilled within known boundaries of a proven oil or gas field, and are located near existing well sites where well parameters are already recorded and necessary surface equipment is in place

. When drilling occurs in areas of new or unknown potential, well parameters such as gas composition, flow rate, and t emperature from the formation need to be ascertained before surface facilities required for production can be adequately sized and brought on site

. In this instance, exploratory (also referred to as “wildcat”) wells and field boundary delineation wells typ ically either vent or combust the flowback gas

. One completion step for improving gas production is to fracture the reservoir rock with very high pressure fluid, typically a water emulsion with a proppant (generally sand) that “props open” the fractures a fter fluid pressure is reduced

. Natural gas e missions are a result of the backflow of the fracture fluids and reservoir gas at high pressure and velocity necessary to clean and lift excess proppant to the surface

. N atural gas from the completion backflow escapes to the atmosphere during the reclamation of water, sand, and hydrocarbon liquids during the collection of the multi

- phase mixture directe d to a surface impoundment

. As the fracture fluids are depleted, the backflow eventually contains a higher volu me of natural gas from the formation

. Due to the additional equipment and resources involved and the nature of the backflow of the fracture fluids, c ompletions involving hydraulic fracturing have higher costs and vent substantially more natural gas than co mpletions not involving hydraulic fracturing.
Hydraulic fracturing can and does occur in some conventional reservoirs, but it is much more common in “tight” formations

. Therefore, this analysis assumes hydraulic fracturing is performed in tight sand, shale , and coalbed methane formations

. This analysis defines tight sand as sandstones or carbonates with an in situ permeability (flow rate capability) to gas of less than 0.1 millidarcy. i

“Energized fractures” are a relatively new type of completion method th at injects an inert gas, such as carbon dioxide or nitrogen, before the fracture fluid and proppant

. Thus, during initial flowback, the gas stream will first contain a high proportion of the injected gas, which wil l gradually decrease overtime.

4.1.2 Oil and Gas Well Recompletions
Many times wells will need supplementary maintenance, referred to as recompletions (these are also referred to as workovers). Recompletions are remedial operations required to maintain production or minimize the decline in pr oduction. Examples of the variety of recompletion activities include

i A darcy (or darcy unit ) and millidarcies (mD) are units of permeability Converted to SI units, 1 darcy is equivalent to 9.869233×10 − 13 m2 or 0.9869233 (μm)2. This conversion is usually approximated as 1 (μm)2.4

- 3

completion of a new producing zone, re

- fracture of a previously fractured zone, removal of paraffin buildup, replacing rod breaks or tubing tears in the wellbore, and addressing a malfunc tioning downhole pump. During a recompletion, portable equipment is conveyed back to the well site temporarily and some recompletions require the use of a service rig. As with well completions, recompletions are highly specialized activities, requiring spe cial equipment, and are usually performed by well service contractors specializing in well maintenance. Any flowback event during a recompletion, such as after a hydraulic fracture, will result in emissions to the atmosphere unless the flowback gas is capt ured.
When hydraulic re

- fracturing is performed, the emissions are essentially the same as new well completions involving hydraulic fracture, except that surface gas collection equipment will already be present at the wellhead after the initial fracture. The backflow velocity during re

- fracturing will typically be too high for the normal wellhead equipment (separator, dehydrator, lease meter), while the production separator is not typically designed for separating sand.

Backflow emissions are not a direct result of produced water

. Backflow emissions are a result of free gas being produced by the well during well cleanup event, when the well also happens to be producing liquids (mostly water) and sand

. The high rate backflow, with intermittent slugs of wat er and sand along with free gas, is typically directed to an impoundment or vessels until the well is fully cleaned up, where the free gas vents to the atmosphere while the water and sand remain in the impoundment or vessels

. Therefore, nearly all of the b ackflow emissions originate from the recompletion process but are vented as the backflow enters the impoundment or vessels. Minimal amounts of emissions are caused by the fluid (mostly water) held in the impoundment or vessels since very little gas is diss olved in the fluid when it enters the impoundment or vessels.

4.2. Emission Data and Emissions Factors
4.2.1 Summary of Major Studies and Emission Factors
Given the potential for significant emissions from completions and recompletions , there have been numerous recent studies conducted to estimate these emissions

. In the evaluation of the emissions and emission reduction options for completions and recompletions , many of these studies were consulted

. Table 4

- 1 presents a list of the studies consulted alo ng with an indication of the type of info rmation contained in the study

.4

- 4 Table 4

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

Report Name Affiliation Year of Report Activity

Factor(s) Emission

Information Control

Information Greenhouse Gas Mandatory Reporting Rule and Technical Supporting Documents 3 EPA 2010 Nationwide X Inventory of Greenhouse Gas Emissions and Sinks: 1990

- 2008 4 , 5 EPA 2010 Nationwide X

Methane Emissions from the Natural Gas Industry 6 , 7 , 8 , 9 Gas Research Institute /US Environmental Protection Agency 1996 Nationwide X X

Methane Emissions from the US Petroleum Industry (Draft) 10 EPA 1996 Nationwide X
Methane E missions from the US Petroleum Industry 11 EPA 1999 Nationwide X
Oil and Gas Emission Inventories for Western States 12 Western Regional Air Partnership 2005 Regional X X Recommendations for Improvements to the Central States Regional Air Partnership's Oil and Gas Emission Inventories 13 Central States Regional Air Partnership 2008 Regional X X

Oil and Gas Producing Industry in Your State 14 Independent Petroleum Association of America 2009 Nationwide

Emissions from Natural Gas Production in the Barnett Shale and Opportunities for Cost

effective Improvements 15 Environmental Defense Fund 2009 Regional X X

Emissions from Oil and Natural Gas Production Facilities 16 Texas Commission for Environmental Quality 2007 Regional X X Availability, Economics and Production of North American Unconventional Natural Gas Supplies 1 Interstate Natural Gas Association of America 2008 NationwideTable 4

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

4

- 5 Report Name Affiliation Year of Report Activity

Factor(s) Emission

Information Control

Information

Petroleum and Natural Gas Statistical Data 17 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 18 EPA 1999 X

Supplemental Generic Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program 19 New York State Department of Environmental Conservation 2009 Regional X X

Natural Gas STAR Program 20 , 21 , 22 , 23 , 24 , 25 EPA 2000

- 2010 Nationwide/

Regional X X4

- 6

4.2.2 Representative Completion and Recompletion Emissions
As previously mentioned, o ne specific emission source during completion and recompletion activities is the venting of natural gas to the atmosphere during flowback. Flowback emissions are short

- term in nature and occur as a specific event during the completion of a new well or duri ng recompletion activities that involve re

- drilling or re

- fracturing of an existing well. For this analysis, well completion and recompletion emissions are estimated as the venting of emissions from the well during the initial phases of well preparation or during recompletion maintenance and/or re

- fracturing of an existing well.
As previously stated, this analysis assumes wells completed/recompleted with hydraulic fracturing are found in tight sand, shale, or coal bed methane formations. A majority of the a vailable emissions data for recompletions is for vertically drilled wells. It is projected that in the future, a majority of completions and recompletions will predominantly be performed on horizontal wells. However, there is not enough history of horizont ally drilled wells to make a reasonable estimation of the difference in emissions from recompletions of horizontal versus vertical wells. Therefore, for this analysis, no distinction was made between vertical and horizontal wells.

As shown in Table 4

- 1, m ethane emissions from oil and natural gas operations have been measured, analyzed and reported in studies spanning the past few decades. The basic approach for this analysis was to approximate methane emissions from representative oil and gas completions a nd recompletions and then estimate volatile organic compounds (VOC) and hazardous air pollutants (HAP) using a representative gas composition

. 26 The specific gas composition ratios used for gas wells were 0. 1459 pounds (lb) VOC per lb methan e (lb VOC/lb met hane) and 0.0106 lb HAP/lb methane. The specific gas composition ratios used for oil wells were 0. 8374 pounds lb VOC/lb met hane and 0. 0001 lb HAP/lb methane.
The EPA’s analysis to estimate methane emissions conducted in support of the Greenhouse Gas Mandat ory Reporting Rule (Subpart W), which was published in the Federal Register on November 30, 2010 (75 FR 74458), was the foundation for methane emission estimates from natural gas completions with hydraulic fracturing and recompletions with hydraulic fracturing. Methane emissions from o il well completion s, oil well recompletion s, natural gas completions without hydraulic fracturing, and natural gas recompletions without hydraulic fracturing were derived directly from the EPA’s Inventory of Greenhouse Gas Emissions and Sinks: 1990

- 2008 (Inventory). 4 A summary of emissions for a representative model well completion or recompleti on is found in Table 4

- 2.4

- 7 Table 4

- 2. Uncontrolled Emissions Estimates from Oil and Natural Gas Well

Completions and Recompletions

Well Completion Category Emissions (Mcf/event) Emissions (tons/event) Methane Methane a VOC b HAP c Natural Gas Well Completion without Hydraulic Fracturing 38.6 0.80 38 0.12 0.009 Natural Gas Well Completion with Hydraulic Fracturing 7,623 158.55 23.13 1.68 Oil Well Completions 0.34 0.007 6 0.00071 0.0000006 Natural Gas Well Recompletion without Hydraulic Fracturing 2.59 0.0538 0.0079 0.0006
Natural Gas Well Recompletion with Hydraulic Fracturing 7,623 158.55 23.13 1.68 Oil Well Recompletions 0.057 0.001 26 0.001 0.0000001 Minor discrepancies may exist due to rounding.
a. Reference 4 , Appendix B., pgs 84

- 89. The conversion used to convert methane from volume to weight is 0.0208 tons methane is equal to 1 Mcf of methane. It is assumed methane comprises 83.081 percent by volume of natural gas from gas wells and 46.732 percent by volume of methane from oil wells. b. Assumes 0.1459 lb VOC /lb methane for natural gas wells and 0.8374 lb VOC/lb methane for oil wells.
c. Assumes 0.0106 lb HAP/lb methane for natural gas wells and 0.0001 lb HAP/lb methane for oil wells

.4

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4.3 Nationwide Emissions from New Sources

4.3.1 Overview of Approach
The first step in this analysis is to estimate nationwide emissions in absence of the proposed rulemaking, referred to as the baseline emissions estimate. In order to develop the baseline emissions estimate, the number of completions and recompletions performed in a typical year was estimated and then multiplied by the expected uncontrolled emissions per well completion listed in Table 4

- 2. In addition, to ensure no emission reduc tion credit was attributed to sources already controlled under State regulations, it was necessary to account for the number of completions/recompletion s already subject to State regulations as detailed below. In order to estimate the number of wells that are already controlled under State regulations, existing well data was analyzed to estimate the percentage of currently controlled wells. This percentage was assumed to also represent the wells that would have been controlled in absence of a federal regula tion and applied to the number of well completions estimated for future years.

4.3.2 Number of Completions and Recompletions
The number of new well completions was estimated using the National Energy Modeling System (NEMS). NEMS is a model of U.S. energy economy developed and maintained by the Energy Information Administration (EIA). NEMS is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the energy economy from the current year to 2035. EIA is legally required to make the NEMS source code available and fully documented for the public. The source code and accompanying documentation is released annually when a new Annual Energy Outlook is produced. Because of the availability of NEMS, numerous agencies, national laboratories, research institutes, and academic and private

- sector researchers have used NEMS to analyze a variety of issues. NEMS models the dynamics of energy markets and their interactions with the broader U.S. economy. The system projects the production of energy resources such as oil, natural gas, coal, and renewable fuels, the conversion of resources through processes such as refining and electricity generation, and the quantity and prices for final consumption across sectors and regions.

Ne w well completion estimates are based on predictions from the NEMS Oil and Gas Supply Model, drawing upon the same assumptions and model used in the Annual Energy Outlook 2011 Reference Case. New well completions estimates were based on total successful we lls drilled in 2015 (the year of analysis for regulatory impacts) for the following well categories: natural gas completions without hydraulic fracturing, natural gas completions with hydraulic fracturing, and oil well completions.4

- 9

Successful wells are ass umed to be equivalent to completed wells. Meanwhile, it was assumed that new dry wells would be abandoned and shut in and would not be completed. Therefore estimates of the number of dry wells were not included in the activity projections or impacts discus sion for exploratory and developmental wells. Completion estimates are based on successful developmental and exploratory wells for each category defined in NEMS that includes oil completions, conventional gas completions and unconventional gas completions. The NEMS database defines unconventional reservoirs as those in shale, tight sand, and coalbed methane formations and distinguishes those from wells drilled in conventional reservoirs. Since hydraulic fracturing is most common in unconventional formations , this analysis assumes new successful natural gas wells in shale, tight sand, and coalbed methane formations are completed with hydraulic fracturing. New successful natural gas wells in conventional formations are assumed to be completed without hydraulic fracturing.
The number of natural gas recompletions with hydraulic fracturing (also referred to as a re

- fracture), natural gas recompletions without hydraulic fracturing and oil well recompletions was based on well count data found in the HPDI ® database. ii , iii The HPDI database consists of oil and natural gas well information maintained by a private organization that provides parameters describing the location, operator, and production characteristics. HPDI ® collects information on a well basis such as the o perator, state, basin, field, annual gas production, annual oil production, well depth, and shut

- in pressure, all of which is aggregated from operator reports to state governments. HPDI was used to estimate the number of recompleted wells because the histo rical well data from HPDI is a comprehensive resource describing existing wells. Well data from 2008 was used as a base year since it was the most recent available data at the time of this analysis and is assumed to represent the number of recompletions th at would occur in a representative year. The number of hydraulically fractured natural gas recompletio ns was estimated by estimating each operator and field combination found in the HPDI database and multiplying by 0.1 to represent 10 percent of the wells being re

- fractured annually (as assumed in Subpart W’ s Technical Supporting Document 3 ). This results in 14,177 total natural gas recompletions with hydraulic fracturing in the U.S. for the year 2008; which is assumed to depict a representative year. Non

- fractured

ii HPDI, LLC is a private organization specializing in oil and gas data and statistical analysis. The HPDI database is focused on historical oil and gas production data and drilling permit data. iii For the State of Pennsylvania, the most recent drilling information available from HPDI was for 2003. Due to the growth of oil and gas operations occurring in the Marcellus region in Pennsylvania, this information would not accurately represent the size of the industry in Pennsylvania for 2006 through 2008. Therefore, information from the Pennsylvania’s Department o f Environmental Protection was used to estimate well completion activities for this region. Well data from remaining states were based on available information from HPDI. From <http://www.marcellusreporting.state.pa.us/OGREReports/Modules/DataExports/DataE xports.aspx4

- 10

recompletions were based on well data for 2008 in HPDI. The number of estimated well completions and recompletions for each well source cat egory is listed in Table 4

- 3.

4.3.3 Level of Controlled Sources in Absence of Federal Regulation
As stated previously, to determine the impact of a regulation, it is first necessary to determine the current level of emissions from the sources being evalua ted, or baseline emissions. To more accurately estimate baseline emissions for this analysis, and to ensure no emission reduction credit was attributed for sources already being controlled, it was necessary to evaluate the number of completions and recompl etions already subject to regulation. Therefore, the number of completions and recompletions already being controlled in the absence of federal regulation was estimated based on the existing State regulations that require control measures for completions a nd recompletions. Although there may be regulations issued by other local ordinances for cities an d counties throughout the U.S., wells impacted by these regulation s were not included in this analysis because well count data are not available on a

co unty or local ordinance level. Therefore, the percentage calculated based on the identified State regulations should be considered a conservative estimate

. In order to determine the number of completions and recompletions that are already controlled under State regulations, EIA historical well count data was analyzed to determine the percentage of new wells currently undergoing completion and recompletion in the States identified as having existing controls. iv Colorado (CO) and Wyoming (WY) were the only St ates identified as requiring controls on completions prior to NSPS review

. T he State of Wyoming’s Air Quality Division (WAQD) requires operators to complete wells without flaring or venting where the following criteria are met: (1) the flowback gas

meets s ales line specifications and (2) the pressure of the reservoir is high enough to enable REC. If the above criteria are not met, then the produced gas is to be flared. 27 The WAQD requires that, “emissions of VOC and HAP associated with the flaring and venti ng of hydrocarbon fluids (liquids and gas) associa ted with well completion and re completion activities shall be eliminated to the extent practicable by routing the recovered liquids into storage tanks and routing the recovered gas into a gas sales line or collection system.” Similar to WY, the Colorado Oil and Gas Conservation Commission (COOGCC) requires REC for both oil and natural gas wells. 28 It was assumed for this analysis that the ratio of natural wells in CO and WY to the total number of wells in the U.S. represents the percentage of controlled wells for well completions. The ratio of wells in WY to the number of total nationwide wells

iv See EIA’s The Number of Producing Wells, http://www.eia.gov/dnav/ng/ng_prod_wells_s1_a.htm4

- 11 Table 4

- 3: Estimated Number of Total Oil and Natural Gas Completions and Recompletion s for a Typical Year

Well Completion Category Estimated Number of Tota l Completions and Recompletions a Estimated

Number of Controlled Completions and Recompletions Estimated

Number of Uncontrolled Co mpletions and Recompletions b Natural Gas Well Completions without Hydraulic Fracturing * 7,694 7,694 Exploratory Natural Gas Well Completions with Hydraulic Fracturing ** 446 446 Developmental Natural Gas Well Completions with Hydraulic Fracturing c 10,957 1,644 9,313 Oil Well Completions d 12,193 12,193 Natural Gas Well Recompletions without

Hydraulic Fracturing 42,342 42,342 Natural Gas Well Recompletions with Hydraulic Fracturing ‡‡ 14,177 2,127 12,050
Oil Well Recompletions ‡ 39,375 39,375

a. Natural gas completions and recompletions without hydraulic fracturing are assumed to be uncontrolled at baseline. b. Fifteen percent of natural gas well completions with hydraulic fracturing are assumed as controlled at baseline.
c. Oil well completions and recompletions are assumed to be uncontrolled at baseline. d. Fifteen percent of natural gas well recompletions with hydraulic fracturing are assumed to be controlled at baseline.4

- 12

was assumed to represent the percentage of controlled well recompletions as it was the only State identified as having regulations dire ctly regulated to recompletions.

From this review it was estimated that 15 percent of completions and 15 percent of recompletions are controlled in absence of federal regulation. It is also assumed for this analysis that only natural gas wells undergoing completion or recompletion with hydraulic fracturing are controlled in these States. Completions and recompletions that are performed without hydraulic fracturing, in addition to oil well completions and recompletions were assumed to not be subject to Sta te regulations and therefore, were assumed to not be regulated at baseline. Baseline emissions for the controlled completions and recompletions covered by regulations are assumed to be reduced by 95 percent from the use of both REC and combustion devices t hat may be used separately or in tandem, depending on the individual State regulation. v The final activity factors for uncontrolled completions and uncontrolled recompletions are also listed in Table 4

- 3.

4.3.4 Emission Estimates
Using the estimated emissi ons, number of uncontrolled and controlled wells at baseline , described above, n ationwide emission estimates for oil and gas well completions and recompletions in a typical
year were calculated and are summarized in Table 4

- 4

. All values have been independ ently rounded to the nearest ton for estimation purposes

. As the table indicates, hydraulic fracturing significantly increases the magnitude of emissions

. Completions and recompletions without hydraulic fracturing have lower emissions, while oil completion s and recompletions have even lower emissions in comparison.

4.4 Control Techniques

4.4.1 Potential Control Techniques
Two techniques were considered that have been proven to reduce emissions from well completions and recompletions: REC and completion combustion. One of these techniques, REC, is an approach that not only reduces emissions but delivers natural gas product to the sales meter that would typically be vented. The second technique, completion combustion, destroys the organic compounds. Both o f these techniques are discussed in the following sections, along with estimates of the impacts of their application for a representative well. Nationwide impacts of chosen regulatory options are discussed in

v Percentage of controls by flares versus REC were not determined, so therefore, the count of controlled wells with REC versus controlled wells with fl ares was not determined and no secondary baseline emission impacts were calculated.4

- 13 Table 4

- 4 . Nationwi de Base line Emissions from Uncontrolled Oil and Gas Well

Completions and Recompletion s

Well Completion Category Uncontrolled

Methane Emissions per event (tpy) Number of

Uncontrolled Wells a Baseline Nationwide Emissions

(tons/ye ar) a

Methane b VOC c HAP d

Natural Gas Well Completions without Hydraulic Fracturing 0.80 38 7,694 6,185 902 66

Exploratory Natural Gas Well Completions with Hydraulic Fracturing 158.55 446 70, 714 10,317 750 Developmental Natural Gas Well Completions with Hydraulic Fracturing 158.55 9,313 1,476,664 215,445 15, 653

Oil Well Completions 0.0076 12,193 93 87 .008

Natural Gas Well Recompletions without Hydraulic Fracturing 0.0538 42,342 2, 2 79 332 24

Natural Gas Well Recompletions with Hydraulic Fracturing 158.55 12,050 1,910,549 278,749 20, 252

Oil Well Recompletions 0.00126 39,375 50 47 .004

Minor discrepancies may be due to rounding.
a. Baseline emissions include emissions from uncontrolled wells plus five percent of emissions from controlled sources. The Baseline emission reductions listed in the Regulatory Impacts (Table 4

- 9) represents only emission reductions from uncontrolled sources. b. The number of controlled and uncontrolled wells estimated based on State regulations.
c. Based on the assumption that VOC content is 0. 1459 pounds VOC per pound methane for natural gas wells and 0.8374 pounds VOC per pound methane for oil wells This estimate accounts for 5 percent of emissions assumed as vented even when controlled

. Does not account for secondary emissions from portion of gas that is directed to a combustion device. d. Based on the assum ption that HAP content is 0.0106 pounds HAP per pound methane for natural gas wells and 0.0001 pounds HAP per pound methane for oil wells

. This estimate accounts for 5 percent of emissions assumed as vented even when controlled

. Does not account for secondary emissions from portion of gas that is directed to a combustion device.4

- 14

section 4.5.

4.4.2 Reduced Emission Completions and Recompletions

4.4.2.1 Description

Reduced emission completions, also referred to as “green” or “flareless” completions, use specially designed equipment at the well site to capture and treat gas so it can be directed to the sales line. This process prevents some natural gas from ve nting and results in add itional economic benefit from the sale of captured gas and, if present, gas condensate

. Additional equipment required to conduct a REC may include additional tankage, special gas

- liquid

- sand separator traps, and a gas dehydrator. 29 In many

cases, portable equipment used for RECs operate in tandem with the permanent equipment that will remain after well drilling is completed. In other instances, permanent equipment is designed (e.g. oversized) to specifically accommodate initial flowback. Some limi tations exist for performing RECs since technical barriers fluctuate from well to well

. Three main limitations include the following for RECs :

 Proximity of pipelines

. For exploratory wells, no nearby sales line may exist

. The lack of a

nearby sales line in curs higher capital outlay risk for exploration and production companies and/or pipeline companies constructing lines in exploratory fields

. The S tate of Wyoming has set a precedent by stating proximity to gathering lines for wells is not a sufficient excu se to avoid RECs unless they are deemed exploratory, or the first well drilled in an area that has never had oil and gas well production prior to that drilling instance (i.e., a wildcat well)

. 30 In instances where formations are stacked vertically and horiz ontal drilling could take place, it may be possible that existing surface REC equipment may be located near an exploratory well, which would allow for a REC.

 Pressure of produced gas . During each stage of the completion/recompletion process, the
pressure o f flowback fluids may not be sufficient to overcome the sales line backpressure. This pressure is dependent on the specific sales line pressure and can be highly variable

. In this case, combustion of flowback gas is one option, either for the duration of t he flowback or until a point during flowback when the pressure increases to flow to the sales line. Another control option is compressor applications

. One application is gas lift which is accomplished by withdrawing gas from the sales line, boosting its pr essure, and routing it down the well4

- 15

casing to push the frac ture fluids up the tubing. The increased pressure facilitates flow into the separator and then the sales line where the lift gas becomes part of the normal flowback that can be recovered during a REC. Another potential compressor application is to boost pressure of the flowback gas after it exits the separator. This technique is experimental because of the difficulty operating a compressor on widely fluctuating flowback rate.

 Inert gas concentratio n

. If the concentration of inert gas, such as nitrogen or carbon dioxide, in the flowback gas exceeds sales line concentration limits, venting or combustion of the flowback may be necessary for the duration of flowback or until the gas energy content incre ases to allow flow to the sales line

. Further, since the energy content of the flowback gas may not be high enough to sustain a flame due to the presence of the inert gases , combustion of the flowback stream would require a continuous ignition source with its own separate fuel supply.

4.4.2.2. Effectiveness
RECs are an effective emissions reduction method for only natural gas completions and recompletion s performed with hyd raulic fracturing based on the estimated flowback emissions described in Section 4.2

. The emissions r eductions vary according to reservoir characteristics and other parameters including length of completion, number of fractured zones, pressure, gas composi tion, and fracturing technology/technique

. Based on several experiences presented at Natural Gas STAR technology transfer workshops , this analysis assumes 90 percent of flowback gas can be recovered during a REC. 31 Any amount of gas that cannot be recovered can be directed to a completion combustion device in order to achieve a minimum 95 percent reduction in emissions.

4.4.2.3 Cost Impacts
All completions incur some costs to a company

. Performing a REC will add to these costs

. Equipment costs associated with RECs vary from well to well

. High production rates may require larger equipment to perform the REC and will increase costs

. If permanent equipment, such as a glycol dehydrator, is already installed or is planned to be in place at the well site as norm al operations, costs may be reduced as this equipment can be used or resized rather than installing a portable dehydrator for temporary use during the completion

. Some operators normally install equipment used in RECs, such as sand traps and three

- phase se parators, further reducing incremental REC costs.4

- 16

Costs of performing a REC are projected to be between $700 and $6,500 per day, with representative well completion flowback lasting 3 to 10 days. 2 This cost range is the incremental cost of performing a REC over a traditional completion, where typically the gas is vented or combusted because there is an absence of REC equipment

. Since RECs involv e techniques and technologies that are new and continually evolving, and these cost estimates are based on the state of the industry in 2006 (adjusted to 2008 US dollars)

. vi Cost data used in this analysis are qualified below:

 $700 per day (equivalent to $ 806 per day in 2008 dollars ) represents completion and recompletion costs where key pieces of equipment, such as a dehydrator or three phase separator, are already found on site and are of suitable design and capacity for use during flowback.

 $6,500 per day ( equivalent to $7,486 in 2008 dollars ) represents situations where key pieces of equipment, such as a dehydrator or three

- phase separator, are temporarily brought on site and then relocated after the completion.

Costs were assessed based on an average of the above data (for costs and number of days per completion) , resulting in an average incremental cost for a REC of $4,146 per day (2008 dollars) for an average of 7 days per completion . This results in an overall incremental cost of $29,022 for a REC versus an uncontrolled completion

. An additional $691 (2008 dollars) was included to account for transportation and placement of equipment , bringing total incremental costs estimated at $29,713. Reduced emission completions are considered one

- ti me events per well; therefore annual costs were conservatively assumed to be the same as capital costs

. Dividing by the expected emission reductions,

co st

- effectiveness for VOC is $ 1,429 per ton, w ith a methane co

- benefit of $ 208 per ton

. Table 4

- 5 provides a summary of REC cost

- effectiveness.
Monetary savings associated with additional gas captured to the sales line was also estimated based on a natural gas price of $4.00 vii per thousand cubic feet (Mcf)

. 32 It was assumed that all gas captured would be included as sales gas. Therefore, assuming that 90 percent of the gas is captured and sold , this equates

vi The Chemical Engineering Cost Index was used to convert dollar years. For REC, the 2008 value equals 575.4 and the 2006 value equals 499.6. vii The average market price for natural gas in 2010 was approximately $ 4.16 per Mcf. This is much less compared to the average price in 2008 of $7.96 per Mcf. Due to the volatility in the price, a conservative savings of $4.00 per Mcf estimate was projected for the analysis in order to not overstate savings. The value of natural gas condensate recovered during the REC would also be significant depending on the gas composition. This value was not incorporated into the monetary savings in order to not overstate savings.4

- 17

Table 4

- 5 . Reduced Emission Completion and Recompletion Emission Reductions and Cost Impacts Summary

Well Completion Category Emission Reduction Per

Completion/ Recompletion (tons/year) a Total Cost Per Completion/ Recompletion b ($ /event ) VOC Cost

Effectiveness ($/ton) c Methane Cost Effectiveness ($/ton)

VOC Methane HAP without savings with

savings without

savings with

savings Natural Gas Completions and Recompletions with Hydraulic Fracturing 20.8 142.7 1.5 29,713 1,429 net savings 208 net

savings
Minor discrepancies may be due to rounding.
a. This represents a ninety percent reduction from baseline for the average well. b. Total cost for reduced emission completion is expressed in terms of incremental cost versus a completion that vents emissions. This is based on an average incremental cost of $ 4,146 per day for an average length of completion flowback lasting 7 days and an additional $691 for transportation and set up.

c. Cost effectiveness has been rounded to the nearest dollar.4

- 18

to a total recovery of 8,258 Mcf of natural gas per completion or recompletion with hydraulic fracturing

. The estimated value of the recovered natural gas for a representative natural gas well with hydrau lic fracturing is approximately $33,030. In addition we estimate an average of 34 ba rrels of condensate is recovered per completion or recompletion. Assuming a condensate value of $70 per barrel ( bbl ) , this result is an income due to condensate sales around $2,380. 33 When considering these savings from REC, for a completion or recompletion with hydraulic fracturing, there is a net savings on the order of $ 5,697 per completion.

4.4.2.4 Secondary Impacts

A REC is a pollution prevention technique that is used to recover natural gas that would otherwise be emitted

. No secondary emissions (e.g., nitrogen oxides, particulate matter, etc.) would be generated, no wastes should be created, no wastewater generated, and no electricity needed

. Therefore, there are no secondary imp acts expected due to REC

.

4.4.3 Completion Combustion Devices

4.4.3.1 Description
Completion combustion is a high

- temperature oxidation process used to burn combustible components, mostly hydrocarbons, found in waste streams. 34 Completion combustion devices are used to control VOC in many industrial settings, since the compl etion combustion device can normally handle fluctuations in concentration, flow rate, heating value, and inert species content. 35 Completion combustion devices commonly found on drilling sites are rather crude and portable, often installed horizontally due to the liquids that accompany the flowback gas

. These flares can be as simple as a pipe with a basic ignition mechanism and discharg e over a pit near the wellhead

. However, the flow directed

to a completion combustion device may or may not be combustible d epending on the inert gas composition of flowback gas, which would require a continuous ignition source

. Sometimes referred to as pit flares, these types of combustion devices do not employ an actual control device, and are not capable of being tested or m onitored for efficiency . They do provide a means of minimizing vented gas and is preferable to venting

. For the purpose of this analysis, the term completion combustion device represents all types of combustion devices including pit flares.4

- 19

4.4.3.2 Effectiveness
The efficiency of completion combustion devices, or exploration and production flare s, can be expected to achieve 95 percent, on average, over the duration of the completion or recompletion. If the energy content of natural gas is low, then t he combustion mechanism can be extinguished by the flowback gas. Therefore, it is more reliable to install an igniter fueled by a consistent and continuous ignition source

. This scenario would be especially true for energized fractures where the initial fl owback concentration will be extremely high in inert gases

. This analysis assumes use of a continuous ignition source with an independent external fuel supply is assumed to achieve an average of 95 percent control over the entire flowback period

. Additiona lly, b ecause of the nature of the flowback ( i.e., with periods of water, condensate, and gas in slug flow), conveying the entire portion of this stream to a flare or other control device is not always feasible

. Because of the exposed flame, open pit flarin g can present a fire hazard or other undesirable impacts in some situations ( e.g., dry, windy conditions, proximity to residences, etc.)

. As a result, we are aware that owners and operators may not be able to flare unrecoverable gas safely in
every case

. Federal regulations require industrial flares meet a combustion efficiency of 98 percent or higher as outlined in 40 CFR 60.18

. This statute does not apply to completion combustion devices

. Concerns have been raised on applicability of 40 CFR 60.18 within the oil and gas industry including for the production segment. 30 , 36 , 37 The design and nature of completion combustion devices must handle multiphase flow and stream compositions that vary during the flowback period

. Thus, the applicability criterion that specifies conditions for flares used in highly industrial settings may not be appropriate for flares typically used to control emissions fr om well completions and recompletion s.
4.4.3.3 Cost Impacts
An analysis depicting the cost for wells including completion combustion devices was conducted for the Petroleum Services Association of Canada (PSAC) 38 in 2009 by N.L. Fisher Supervision and Engi neering, Ltd. viii The data corresponds to 34 gas wells for various types of formations, including coal bed methane and shale

. Multiple completion methods were also examined in the study including hydraulic and energized fracturing

. Using the cost data points from these natural gas well completions,

viii It is important to note that outliers were excluded from the average cost calculation

. Some outliers estimated the cost of production flares to be as low as $0 and as high as $56,000

. It is expected that these values are not repres entative of typical flare costs and were removed from the data set. All cost data found in the PSAC study were aggregated values of the cost of production flares and other equipment such as tanks. It is possible the inclusion of the other equipment is not only responsi ble for the outliers, but al so provides a conservatively high estimate for completion flares.4

- 20

an average completion combustion device cost is approximately $3,523 (2008 dollars). ix As with the REC, because completion combustion devices are purchased for these one

- time events, annual costs were conservatively assumed to be equal to the capital costs.
It is assumed that the cost of a continuous ignition source is included in the combustion completion device cost estimations

. It is understood that multiple completions and recompletions can be controlled with the same completion combustion device , not only for the lifetime of the combustion device but within the same yearly time period

. However, to be conservative, c osts were estimated as the total cost of the completion combustion device itself, which corresponds to the assumption that only one device will control one completion per year

. The cost impacts of using a completion combustion device to reduce emissions from representative completions/ recompletions are provided in Table 4

- 6

. C o mpletion combustion devices have a cost

- effectiveness of $ 161 per ton VOC and a co

- benefit of $23 per ton methane for completions and recompletions with hydraulic fracturing.

4.4.3.4 Secondary Impacts
Noise and heat are the two primary undesirable outcome s of completion combustion device operation

. In addition, combustion and partial combustion of many pollutants also create secondary pollutants including nitrogen oxides (NO x ) , carbon monoxide (CO) , sulfur oxides (SO x , carbon dioxide (CO 2 ) , and smoke/particulates (PM)

. The degree of combustion depends on the rate and extent of fuel mixing with air and the temperature maintained by the flame

. Most hydrocarbons with carbon

- to

- hydrogen ratios greater than 0.33 are likely to smoke. 34 Due to the high methane content of the gas stream routed to the completion combustion device , it suggests that there should not be smoke except in specific cir cumstances (e.g., energized fractures)

. The stream to be combusted may also contain liquids and solids that will also affect the potential for smoke

. Soot can typically be eliminated by adding steam

. Based on current industry trends in the design of comple tion combustion devices and in the decentralized nature of completions, virtually no completion combustion devices include steam assistance. 34

Reliable data for emission factors from flare operations during natural gas well completions are limited

. Guidelines published in AP

- 42 for flare operations are based on tests from a mixture containing

ix The Chemical Engineering Cost Index was used to convert dollar years. For the combustion device the 2009 value equals 521.9. The 2009 average value for the combustion device is $3,195.4

- 21 Table 4

- 6 . Emission Reduction and Cost

- effectiveness Summary

for Completion Combustion Devices

Well Completion Category Emission Reduction Per

Completion/Workover (tons/year) a Total Capital Cost Per Completion Event ($)* VOC Cost

Effectiveness Methane

Cost Effectiveness

VOC Methane HAP ($/ton) b ($/ton) Natural Gas Well Completions without Hydraulic Fracturing 0.11 0.76 0.0081

3,523 31,619 4,613

Natural Gas Well Completions with Hydraulic Fracturing 21.9 150.6 1.597 160 23

Oil Well Completions 0.01 0.007 0.0000007 520,580 488,557
Natural Gas Well Recompletions without Hydraulic Fracturing 0.007 0.051 0.0005 47 2,227 68,8 89

Natural Gas Well Recompletions with Hydraulic Fracturing 21.9 150.6 1.597 160 23

Oil Well Recompletions 0.00 0.001 0.0000001 3, 134,431 2,941,615 Minor discrepancies may be due to rounding.
a. This assumes one combustion device will control one completion event per year. This should be considered a conservative estimate, since it is likely multiple completion events will be controlled with the same combustion unit in any given year. Costs are st ated in 2008 dollars.4

- 22

80 percent propylene and 20 percent propane. 34 These emissions factors, however, are the best indication for secondary pollutants from flare operations currently available. These secondary emission factors are provided are provided in Tab le 4

- 7.
Since this analysis assumed pit flares achieve 95 percent efficiency over the duration of flowback, it is likely the secondary emission estim ations are lower than actuality (i.e. AP

- 42 assumes 98 percent efficiency ). In addition due, to the potent ial for the incomplete combustion of natural gas across the pit flare plume, the likelihood of additional NO x formulating is also likely. The degree of combustion is variable and depends on the on the rate and extent of fuel mixing with air and on the flam e temperature. Moreover, the a ctual NO x (and CO) emissions may be greatly affected when the raw gas contains hydrocarbon liquids and water. For these reasons, the n ationwide impacts of combustion devices discussed in Section 4.5 should be considered minimu m estimates of secondary emissions from combustion devices

.

4.5 Regulatory Options
The REC pollution prevention approach would not result in emissions of CO, NO x , and PM from the combustion of the completion gases in the flare, and would therefore be the preferred option

. As discussed above, REC is only an option for reducing emissions from gas well completions/workovers with hydraulic fracturing

. Taking this into consideration, the following regulatory alternatives were

ev aluated:

 Regulatory Option 1: Req uire completion combustion devices for conventional natural gas well completions and recompletions;

 Regulatory Option 2: Require completion combustion devices for oil well completions and recompletions;

 Regulatory Option 3: Require c ombustion devices for a ll completions and recompletions;

 Regulatory Option 4: Require REC for all completions and recompletions of hydraulically fractured wells ;

 Regulatory Option 5: Require REC and combustion operational standards for natural gas well completions with hydrauli c fracturing, with the exception of exploratory, and delineation wells;

 Regulatory Option 6: Require combustion operational standards for exploratory and delineation wells; and4

- 23

Table 4

- 7 . Emission Factors from Flare Operations from AP

- 42 Guidelines Tabl e 13.4

- 1 a

Pollutant Emission Factor (lb/10 6 Btu) Total Hydrocarbon b 0.14 Carbon Monoxide 0.37 Nitrogen Oxides 0.068 Particular Matter c 0

- 274 Carbon Dioxide d 60
a. Based on combustion efficiency of 98 percent. b. Measured as methane equivalent.
c. Soot in concentration values: nonsmoking flares, 0 micrograms per liter (μg/L); lightly smoking flares, 40 μg/L; average smoking flares, 177 μg/L; and heavily smoking flares, 274 μg/L. d. Carbon dioxide is measured in kg CO2/MMBtu and is derived from the carb on dioxide emission factor obtained from 40 CFR Part 98, subpart Y, Equation Y

- 2.4

- 24

 Regulatory Option 7: Require REC and combustion operational standards for all natural gas well recompletions with hydraulic fracturing.
The following sections discuss thes e regulatory options.

4.5.1 Evaluation of Regulatory Options
The first two regulatory options ( completion combustion devices for conventional natural gas well completions and recompletions and completion combustion devices for oil well completions and

reco mpletions) were evaluated first. As shown in Table 4

- 6, the cost effectiveness associated with controlling conventional natural gas and oil well completions and recompletions ranges from $ 31,60 0
per ton VOC to over $3.7 million per ton VOC. Therefore, Regu latory Options 1 and 2 were rejected due to the high cost effectiveness.
The next regulatory option, to re quire completion c ombustion devices for all completions and recompletions, was considered. Under Regulatory Option 3, all of the natural gas emitted f rom the well during flowback would be destroyed by sending flowback gas through a combustion unit . Not only would this regulatory option result in the destruction of a natural resource with no recovery of salable gas, it also would result in an increase in emissions of secondary pollutants (e.g., nitrogen oxides, carbon monoxide, etc.). Therefore, Regulatory Option 3 was also rejected.
The fourth regulatory option would re quire REC s for all completions and recompletions of hydraulically fractured wells . As stated previously, RECs are not feasible for all well completions, such as exploratory wells, due to their distance from sales lines, etc. Further, RECs are also not technically feasible for each well at all times during completion and recompletion ac tivities due to the variability of the pressure of produced gas and/or inert gas concentrations. Therefore, Regulatory Option 4 was rejected.
The fifth regulatory option was to require an operational standard consisting of a combination of REC and combusti on for natural gas well completions with hydraulic fracturing. As discussed for Regulatory Option 4, RECs are not feasible for every well at all times during completion or recompletion activities due to variability of produced gas pressure and/or inert gas concentrations

. In order to allow for wellhead owners and operators to continue to reduce emissions when RECs are not feasible due to well characteristics (e.g, wellhead pressure or inert gas concentrations), Regulatory Option 5 also allows for the use of a completion combustion device in combination with RECs.4

- 25

Under Regulatory Option 5, a numerical limit was considered, but was rejected in favor of an operational standard. Under section 111(h)(2) of the CAA, EPA can set an operational standard which
repre sents the best system of continuous emission reduction, provided the following criteria are met:

“ (A) a pollutant or pollutants cannot be emitted through a conveyance designed and constructed to emit or capture such pollutant, or that any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State, or local law, or

(B) the application of measurement methodology to a particular class of sources is not practicable due to technological or economic limitations. ”

As discussed in section 4.4.3, emissions from a completion combustion device cannot be measured or monitored to d etermine efficiency making an operational standard appropriate. Therefore, an operational standard under this regulatory option consist s of a combination of REC and a completion combustion device to minimize the venting of natural gas and condensate vapors to the atmosphere, but allows venting in lieu of combustion for situations in which combustion would present safety hazards, other

concerns , or for periods when the flowback gas is noncombustible due to high concentrations of inert gases. Sources would al so be required, under this regulatory option, to maintain documentation of t he overall duration of the completion event, duration of recovery using REC, duration of combustion, duration of venting, and specific reasons for venting in lieu of combustion . It was also evaluated whether Regulatory Option 5 should apply to all well completions, including exploratory and delineation wells.
As discussed previously, one of the technical limitations of RECs is that they are not feasible for use at

some well s due to their proximity to pipelines

. Section 111(b)(2) of the CAA allows EPA to “...distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing....” performance standards

. Due to their distance from sales lines, and t he relatively unknown characteristics of the formation, completion activities occurring at exploratory or delineation wells were considered to be a different “type” of activity than the types of completion activities occurring at all other gas wells

. There fore, two subcategories of completions were identified: Subcategory 1 wells are all natural gas wells completed with hydraulic fracturing that do not fit the definition of exploratory or delineation wells

. Subcategory 2 wells are natural gas wells that mee t the following definition s of exploratory or delineation wells :4

- 26

 Exploratory wells are wells outside known fields or the first well drilled in an oil or gas field where no other oil and gas production exists or

 Delineation wells means a well drilled in order to determine the boundary of a field or producing reservoir.
Based on this subcategorization, Regulatory Option 5 would apply to the Subcategory 1 wells and a sixth regulatory option was developed for Subcategory 2 wells.
Regulatory Option 6 requires an operational standard for combustion for the Subcategory 2 wells. As described above, REC is not an option for exploratory and delineation wells due to their distance from sales lines. As with the Regulatory Option 5, a numerical limitation is not feasi ble. Therefore, this regulatory option requires an operational standard where emissions are minimized using a completion combustion device during completion activities at S ubcategory 2 wells, with an allowance for venting in situations where combustion pre sents safety hazards or other concerns or for periods when the flowback gas is noncombustible due to high concentrations of inert gases. Consistent with Regulatory Option 5, records would be required to document the overall duration of the completion event , the duration of combustion, the duration of venting, and specific reasons for venting in lieu of combustion

. The final regulatory option was considered for recompletions. Regulatory Option 7 requires an operational standard for a combination of REC and a completion combustion device for all recompletions with hydraulic fracturing performed on new and existing natural gas wells. Regulatory Option 7 has the same requirements as Regulatory Option 5. Subcategorization similar to Regulatory Option 5 was not ne cessary for recompletions because it was assumed that RECs would be technically feasible for recompletions at all types of wells since they occur at wells that are producing and thus proximity to a sales line is not an issue. While evaluating this regulato ry option, it was considered whether or not recompletions at existing wells should be considered modifications and subject to standards.
The affected facility under the New Source Performance Standards (NSPS) is considered to be the wellhead. Therefore, a new well drilled after the proposal date of the NSPS would be subject to emission control requirements. Likewise, wells drilled prior to the proposal date of the NSPS would not be subject to emission control requirements unless they underwent a modificatio n after the proposal date. Under section 111(a) of the Clean Air Act, the term “modification” means :4

- 27

“any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such sou rce or which results in the emission of any air pollutant not previously emitted.”
The wellhead is defined as the piping, casing, tubing, and connected valves protruding above the earth’s surface for an oil and/or natural gas well. The wellhead ends wher e the flow line connects to a wellhead valve

. In order to fracture an existing well during recompletion, the well would be re

- perforated, causing physical change to the wellbore and casing and therefore a physical change to the wellhead, the affected facil ity. Additionally, much of the emissions data on which this analysis is based demonstrates that hydraulic fracturing results in an increase in emissions. Thus, recompletions using hydraulic fracturing result in an increase in emissions from the existing we ll producing operations. Based on this understanding of the work performed in order to recomplete the well, it was determined that a recompletion would be considered a modification under CAA section 111(a) and thus, would constitute a new wellhead affected facility subject to NSPS. Therefore, Regulatory Option 7 applies to recompletions using hydraulic fracturing at new and existing wells.
In summary, Regulatory Options 1, 2, 3, and 4 were determined to be unreasonable due to cost considerations, other impa cts or technical feasibility and thereby rejected. Regulatory Options 5, 6, and 7 were determined to be applicable to natural gas wells and were evaluated further.

4.5.2 Nationwide Impacts of Regulatory Options
This section provides an analysis of the primary environmental impacts (i.e., emission reductions), cost impacts and secondary environmental impacts related to Regulatory Options 5, 6, and 7 which were selected as viable options for setting standards for completions and recompletions.

4.5.2 .1 Pri mary Environmental Impacts of Regulatory Options
Regulatory Options 5, 6, and 7 were selected as options for setting standards for completions and regulatory options as follows:

 Regulatory Option 5 : O perational standard for completions with hydraulic fracturing for Subcategory 1 wells (i.e., wells which do not meet the definition of exploratory or delineation wells) , which requires a combination of REC with combustion, but allows for venting during specified situations.4

- 28

 Regulatory Option 6: An operatio nal standard for completions with hydraulic fracturing for exploratory and delineation wells (i.e., Subcategory 2 wells) which requires completion combustion devices with an allowance for venting during specified situations.

 Regulatory Option 7: An operati onal standard equivalent to Regulatory Option 5 which applies to recompletions with hydraulic fracturing at new and existing wells.
The number of completions and recompletions that would be subject to the regulatory options listed abo ve was presented in Ta ble 4

- 3. It was estimated that there would be 9,313 uncontrolled developmental natural gas well completions with hydraulic fracturing s ubject to Regulatory Option 5. Regulatory Option 6 would apply to 446 uncontrolled exploratory natural gas well completio ns with hydraulic fracturing, and 12,050 uncontrolled recompletions at existing wells would be s ubject to Regulatory Option 7. x

Table 4

- 8 presents the nationwide emission reduction estimat es for each regulatory option. It was estimated that RECs in combin ation with the combustion of gas unsuitable for entering the gathering line, can achieve an overall 95 percent VOC reduction over the duration of the completion operation

. The 95 percent recovery was estimated based on 90 percent of flowback being captured to the sales line and assuming an additional 5 percent of the remaining flowback would be sent to the combustion device. Nationwide emission reductions were estimated by apply ing this 95 percent VOC reduction to the uncontrolled baseline emissions presented in Table 4

- 4.

4.5

. 2. 2 Cost Impacts
Cost impacts of the individual control techniques (RECs and completion combustion devices) were presented in section 4.4. For Regula tory Option 6, the costs for completion combustion devices presented in Table 4

- 6 for would apply to Subcategory 2 completions

. The cost per completion event was estimated to be $3,523

. Ap p lied to the 446 estimated Subcategory 2 completions, the nationwide costs were estimated to be $1.57 million. Completion combustion devices are assumed to achieve an overall 95 percent combustion efficiency. Since the operational standards for Regulatory Options 5 and 7 include both REC and completion combustion devices, an additional cost impact analysis was

x The number of uncontrolled recompletions at new wells is not included in this analysis. Based on the assumption that wells are recompleted once every 10 years, any new wells that are drilled after the date of proposal of the standard would not like ly be r ecompleted until after the year 2015, which is the date of this analysis. Therefore, impacts were not estimated for recompletion of new wells, which will be subject to the standards.4

- 29 Table 4

- 8 . Nationwide Emission and Cost Analysis of Regulatory Option

Minor discrepancies may be due to rounding.
a. Number of sources in each well completion category that are uncontrolled at baseline as presented in Table 4

- 3. b. Costs per event for Regulatory Options 5 and 7 are calculated by adding the costs for REC and completion combustion device presented in Tables 4

- 5 and 4

- 6, respectively

. Cost per event for Regulatory Option 6 is presented for com pletion combustion devices in Table 4

- 6

. c. Nationwide emission reduction s calculated by applying the 95 percent emission reduction efficiency to the uncontrolled nationwide baseline emissions in Table 4

- 4. Well Completion Category Number

of Sources subject to NSPS a Annual

Cost Per Completio n Event ($) b Nationwide Emission

Reductions (tpy) c VOC Cost Effectiveness ($/ton) Methane Cost

Effectiveness ($/ton) Total Nationwide Costs

(million $/year)

VOC Methane HAP without savings with

savings without

savings with

savings Capital

Cost Annual

without savings Annual

with savings Regulatory Option 5 (operational standard for REC and combustion) Subc ategory 1 : Natural gas Completions with Hydraulic Fracturing 9,313 33,237 204,134 1,399,139 14,831 1,516 net savings 221 net savings 309.5 309.5 (20.24)

Regulatory Option 6 (operational standard for combustion) Subc ategory 2 : Natural gas Completions with Hydraulic Fracturing 446 3,523 9,801 67,178 712 160 160 23 23 1.57 1.57 1.57

Regulatory Option 7 (operational standard for REC and combustion)
Natural Gas Well Recompletions with Hydraulic Fracturing 12,050 33,237 264,115 1,810,245 19,189 1,516 net savings 221 net savings 400.5 400.5 (26.18)4

- 30

performed to analyze the nationwide cost impacts of these regulatory options. The total incremental cost of the operational standard for Subcategory 1 completions and for recompletions is estimated at around $33,237, which includes the costs in Table 4

- 5 for the REC equipment and transportation in addition to the costs in Table 4

- 6 for the completion combustion device. Applying the cost for the combined REC and completion combustion device to the estimated 9,313 Subcategory 1 completions, the total nationwide cost was estimated to be $309.5 million, with a net annual savings estimated around $20 million when natural gas savings are considered. A cost of $400.5 million was estimated for recompletions, with an overall savings of around $26 million when natural gas savings are consider ed. The VOC cost effectiveness for Regulatory Options 5 and 7 was estimated at around $ 1,516 per ton, with a methane co

- benefit of $221 per ton.

4.5. 2. 3 Secondary Impacts
Regulatory Options 5, 6 and 7 all require some amount of combustion; therefore the e stimated nationwide secondary impacts are a direct result of combusting all or partial flowback emissions. Although, it is understood the volume of gas captured, combusted and vented may vary significantly depending on well characteristics and flowback com position, for the purpose of estimating secondary impacts for Regulatory Options 5 and 7, it was assumed that ninety percent of flowback is captured and an additional five percent of the remaining gas is combusted. For both Subcategory 1 natural gas well

c ompletions with hydraulic fracturing and for natural gas well recompletions with hydraulic fracturing, it is assumed around 459 Mcf of natural gas is combusted on a per well basis. For Regulatory Option 6, Subcategory 2 natural gas completions with hydraul ic fracturing, it is assumed tha t 95 percent (8,716 M cf) of flowback emissions are consumed by the combustion device. Tons of pollutant per completion event was estimated assuming 1,089.3 Btu/scf saturated gross heating value of the "raw" natural gas and applying the AP

- 42 emissio ns factors listed in Table 4

- 7.
From category 1 well completions and from recompletions, it is estimated 0.02 tons of NO x are produced per event. This is based on assumptions that 5 percent of t he flowback gas is combusted by the combustion device. From category 2 well completions, it is estimated 0.32 tons of NO x are produced in secondary emissions per event. This is based on the assumption 95 percent of flowback gas is combusted by the combusti on device. Based on the estimated number of completions and recompletions, the proposed regulatory options are estimated to produce around 507 tons of NO x in secondary emissions nationwide from controlling all or partial flowback by combustion

. Table 4

- 9 s ummarizes the estimated secondary emissions of the selected regulatory options.4

- 31 Table 4

- 9 Nationwide Secondary Impacts of Selected Regulatory Options a

Pollutant Regulatory Options 5 b Regulatory Option 6 c Regulatory Options 7 b Subc ategory 1 Natural Gas Well Completions with Hydraulic Fracturing Subc ategory 2 Natural Gas Well Completions with Hydraulic Fracturing Natural Gas Well Recompletions with Hydraulic

Fracturing

tons per event d Nationwide

Annual Secondary Emissions (tons/year) tons per

event d Nationwide

Annual Secondary Emissions (tons/year) tons per

event d Nationwide

Annual Secondary Emissions (tons/year) Total Hydrocarbons 0.03 326 0.66 296 0.03 422 Carbon Monoxide 0.09 861 1.76 783 0.09 1,114 Nitrogen Oxides 0.02 158 0.32 144 0.02 205 Particulate Matter 0.00000002 0.0002 0.011 5 0.00000002 0.0003 Carbon Dioxide 33 .06 307,863 628 280,128 33.06 398,341

a. Nationwide impacts are based on AP

- 42 Emission Guidelines for Industrial Flares as outlined in Table 4

- 7 . As such, these emissions should be considered the minimum level of secondary emissions expected. b. The operational standard (Regulatory Options 5 and 7) combines REC and combustion is assumed to capture 90 percent of flowbac k gas. Five percent of the rema ining flowback is assumed to be consumed in the combustion device. Therefore, it is estimated 459 Mcf is sent to the combustion device per completion event. This analysis assumes there are 9,313 Subcategory 1 wells and 12,050 recompletions.
c. Assumes 8,716 Mcf of natural gas is sent to the combustion unit per completion. This analysis assumes 446 exploratory wells fall into this category. d. Based on 1,089.3 Btu/scf saturated gross heating value of the "raw" natural gas

.4

- 32

4.6 References

1

. ICF Consulting. Availability, Economics, and Production Potential of North American Unconventional Natural Gas Supplies. Prepared for INGAA Foundation, Inc. November 2008. www.ingaa.org/File.aspx?id=7878

. 2

. U.S. Environmental Protection Agency

. Lessons Learned : Reduced Emissions Completions. Office of Air and Radiation: Natural Ga s Star Program. Washington, DC. 20 11

. 3

. 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. 84

- 89 pp.

4 U.S Environmental Protection Agency. Methodology for Estimating CH 4 and CO 2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 1990

- 2008. Washington, DC. 2010.

5

. U.S Environmental P rotection Agency. Methodology for Estimating CH 4 and CO 2 Emissions from Natural Gas Systems

. Greenhouse Gas Inventory: Emission and Sinks 1990

- 2008. Washington, DC. 2010.

6

. 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.

7

. Radian International LLC

. Methane Emissions from the Natural Gas Indus try, Vol. 3: General Methodology. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA

- 600/R

- 96

- 080c. June 1996.

8

. Radian International LLC

. Methane Emissions from the Natural Gas Industry, Vol. 5: Activity Factors. Prepared f

or the Gas Research Institute and Environmental Protection Agency. EPA

600/R

- 96

- 080e. June 1996

9

. 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.

10

. Radian International LLC, Methane Emissions from the U.S. Petroleum Industry , draft report for the U.S. Environmental Protection Agency, June 14, 1996.

11

. ICF Consulting . Estimates of Methane Emissions from the U.S. Oil Industry. Prepared for the U.S. Environmental Protection Agency. 1999.

12

. ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States. Prepared for Western Governors’ Association. December 27, 2005.4

- 33

13

. 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.

14

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

. 2008.

15

. Armendariz, Al. Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost

- Effective Improvements. Prepared for Environmental Defense Fund. January 2009.

16

. Eastern Research Group, Inc. Emissions from Oil and Gas Production Facilities. Prepared for the Texas Commission on Environmental Quality. August 31, 2007.

17

. U.S. Energy Information Administration

. Annual U. S. Natural Gas Wellhead Price

. Energy Information Administration. Natural Gas Navigator. Retrieved December 12, 2010. http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm

. 18

. Eastern Research Gr oup, 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.

19

. New York State Department of Environmental Cons ervation

. Supplemental Generic Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program (DRAFT). September 2009.

20

. U.S. Environmental Protection Agency. Reduced Emission Completions (Green Completions). Natural Gas STAR. Pro ducers Technology Transfer Workshop. 2005. Slide 12.

21

. Anadarko Petroleum Corporation. Reduced Emission Completions in DJ Basin and Natural Buttes. Producers Technology Transfer Workshop. Rock Springs, WY. 2008. http://www.epa.gov/gasstar/documents/workshops/2008

- tech

- transfer/rocksprings5.pdf

22

. Ellwood, B. Reduced Emissions Completions Jonah Case Study. EnCana. Denver, CO. 2009. http://www.epa.gov/gasstar/documents/workshops/2009

- annual

- conf/08ellwood.pdf

23

. Marathon. Excape Completion Process Reduces Gas Emissions and Speeds Well Completions. 14 th Annual Natural Gas Star Workshop. Houston, TX. 2007 http://www.epa.gov/gasstar/documents/workshops/2007

- annual

- conf/06_phil_snider.pdf

24

. Werline, R. Natural Gas Star Workshop. Oklahoma City, OK. 2009. http://www.epa.gov/gasstar/documents/workshops/okcity2009/devon_completions.pdf

25

. US Environmental Protection Agency. Reducing Methane Emissions During Completion Operations. Natural Gas STAR. Annual Implement ation Workshop. Houston, TX

. 2006. http://www.epa.gov/gasstar/documents/vincent.pdf

26

. Memorandum to B ruce Moore from Heather Brown. Composition of Natural Gas for Use in the Oil and Natural Gas Sector Rulemaking. EC/R, Incorporated. June 29, 2011

.4

- 34

27 Sta te of Wyoming Department of Environmental Quality, Air Quality Division. Well Completions/Re

- completions Permit Application . Page 2. August 2010. http://deq.state.wy.us/aqd/Oil%20and%20Gas/AQD

OG11_Green%20Completion%20Application.pdf

28 Colorado Oil and G as Conservation Commission. 2 CCR

- 404

- 1. http://oil

gas.state.co.us/RuleMaking/FinalDraftRules/COGCCFinalDraftRules_110708.pdf

29

. U.S. Environmental Protection Agency Fact Sheet No. 703: Green Completions

. Office of Air
a nd Radiation: Natural Gas Star Program. Washington, DC. September 2004.

30

. Memorandum to Bruce Moore from Denise Grubert. Americ an Petroleum Institute Meeting Minutes. EC/R, Incorporated. July 2010.

31 Memorandum to Bruce Moore from ICF Consulting. Percent of Emissions Recovered by Reduced Emission Completions. May 2011.

32

. U.S. Energy Information Administration

. Annual U.S. Natural Gas Wellhead Price

. Energy Information Administration. Natural Gas Navigator. Retrieved online on Dec 12, 2010. http://www.eia.doe.gov/dnav/ng/hist/n919 0us3a.htm

33 Memorandum to Bruce Moore from ICF Consulting. NSPS Unconventional Well Completions Condensate Recovery Analysis

– Recovered Volumes and Value. July 28, 2011.

34

. U.S. Environmental Protection Agency

. AP 42, Fifth Edition, Volume I, Chapter 13.5 Industrial Flares. Office of Air Quality Planning & Standards. 1991

35

. U.S. Environmental Protection Agency. Air Pollution Control Technology Fact Sheet: FLARES. Clean Air Technology Center.

36

. Memorandum to Bruce Moore from Denise Grubert. American Petroleum Institute Meeting Minutes. EC/R, Incorporated. October 2010.

37

. Memorandum to Bruce Moore from Denise Grubert. American Petroleum Institute Meeting Minutes Attachment 1: Review of Federal Air Regulations for the Oil and Natural Gas Sector 40 CF R Part 60, Subparts KKK and LLL; 40 CFR Part 63 Subparts HH and HHH. EC/R, Incorporated. February 2011.

38

. Petroleum Services Association of Canada. 2009 Well Cost Study. Upcoming Summer Costs. Well Cost Data and Consulting by N.L. Fisher Supervision & Engineering Ltd. April 30, 2009.5

- 1 5.0 PNEUMATIC CONTROLLER S
The natural gas industry uses a variety of process control devices to operate valves that regulate pressure, flow, temperature, and liquid levels

. Most instrumentation and control equipment falls into one of three categories: (1) pneumatic; (2) electrical; or (3) mechanical

. Of these, only pneumatic devices are direct sources of air emissions. Pneumatic controllers are used throughout the oil and natural gas sector as part of the instrumentation to control the position of valves. This chapt er describes pneumatic de vices including their function and associated emissions

. Options available to reduce emissions from pneumatic devices are presented, along with costs, emission reductions, and secondary impacts

. Finally, this chapter discusses considerations in developing regulatory alternatives for pneumatic devices.

5.1 Process Description
For the purpose of this document, a pneumatic controller is a device that uses natural gas to transmit a process signal or condition pneumatically and that may also adjust a valve position based on that signal, with the same bleed gas and/or a supplemental supply of power gas

. In the vast majority of applications, the natural gas industry uses pneumatic controllers that make use of readily available high

- pressure natural gas to provide the required energy and control signals

. In the production se gment , an estimated 400,000 pneumatic devices control and monitor gas a nd liquid flows and levels in dehydrators and separators, temperature in dehydrator regenerators, and pressure in flash tanks

. There are around 13,000 gas pneumatic controllers located in the gathering, boosting and processing segment that control and moni tor temperature , liquid , and pressure levels

. In the transmission segment , an estimated 85,000 pneumatic controllers actuate isolation valves and regulate gas flow and pressure at compressor stations, pipelines, and storage facilities. 1

Pneumatic controlle rs are automated instruments used for maintaining a process condition such as liquid level, pressure, pressure differential, and temperatu re. In many situations across all segments of the oil and gas industry, pneumatic controllers make use of the available high

- pr essure natural gas to operate control of a valve

. In these “gas

- driven” pneumatic controllers, natural gas may be released with every valve movement and/ or continuously from the valve control pilot. The rate at which th e continuous release occurs is referre d to as the bleed rate. Bleed rates are dependent on the design and operating characteristics of the devic e. Similar designs will have similar steady

- state rates when oper ated under similar conditions. There are three basic designs: (1) c ontinuous bleed devices are used to modulate flow, liquid level, or pressure, and gas is vented continuously at a rate that may vary over time ; (2) snap

-5

- 2

acting devices release gas only when they open or close a valve or as they throttle the gas flow; and ( 3) self

- contained devices release gas to a downstream pipeline instead of to the atmosphere. This analysis assumes self

- contained devices that release natural gas to a downstream pipeline instead of to the atmosphere have no emissions . Furthermore, it is r ecognized “closed loop” systems are applicable only in instances with very low pressure 2 and may not be suitable to replace many applications of bleeding pneumatic devices. Therefore, these devices are not further discussed in this analysis.

Snap

- acting co ntrollers are devices that only emit gas during actuation and do not h ave a continuous bleed rate

. The actual amount of emissions from snap

- acting devices is dependent on the amount of natural gas vented per actuation and how often it is actuated. Bleed devices also vent a n additional volume of gas during actuation , in addition to the device‟s bleed stream

. Since a ctuation emissions serve the device‟s functional purpose and can be highly variable , t he emissions characterized for high

- bleed and low

- bleed d evices in this analysis (as described in section 5.2.2) account for only the continuous flow of emissions (i.e. the bleed rate) and do not include emissions directly resulting from actuation. Snap

- acting controllers are assumed to have zero bleed emissions

. M ost applications (but not all), snap

acting devices serve functionally different purposes than bleed devices. Therefore, snap

- acting controllers are not further discussed in this analysis.

In addition , n ot all pneumatic controllers are gas driven. At s ites without electrical service sufficient to power an instrument air compressor, mechanical or electrically powered pneumatic devices can be used. These “non

- gas driven” pneumatic controllers can be mechanically operated or use sources of power other than pressurized natural gas, such as compressed “instrument air.” Because these devices are not gas driven, they do not directly releas e natural gas or VOC emissions. However, electrically powered systems have energy impacts, wi th associated secondary impacts related to generation of the electrical power required to drive the instrument air compressor system. Instrument air systems are feasible only at oil and natural gas locations where the devices can be driven by compressed in strument air systems and have electrical service suffic ient to power an air compressor. This analysis assumes that natural gas processing plants are the only facilities in the oil and natural gas sector highly likely to have electrical service sufficient t o power an instrument air system, and that most existing gas processing plants use instrument air instead of gas driven devices. 9 The application o f electrical controls is further elaborated
in Section 5.3

.5

- 3

5.2 Emissions Data and Information

5.2.1 Summary of Major Studies and Emissions

In the evaluation of the emissions from pneumatic devices and the potential options available to reduce these emissions, nu merous studies were consulted. Table 5

- 1 lists these references with an indication of the type of relevant information contained in each study.

5.2.2 Representative Pneumatic Device Emissions

Bleeding pneumatic controllers can be classified in to two types 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 standard cubic feet per hour (scfh), while low

- bleed d evices bleed at a rate less than or equal to 6 scfh. i

For this analysis, EPA consulted information in the appendices of the Natural Gas STAR Lessons Learned document on pneumatic devices , Subpart W of the Greenhouse Gas Reporting rule, as well as obtained updated dat a from major vendors of pneumatic devices

. The data obtained from vendors included emission rates, costs, and any other pertinent information for each pneumatic device model (or model family)

. All pneumatic devices that a vendor offered were itemized and i nquir ies were made into the specifications of each device and whether it was applicable to oil and natural gas operations. High

bleed and low

- bleed devices were differentiated using the 6 scfh threshold.
Although by definition, a low

- bleed d evice can emit up to 6 scf h, through this vendor research , it was determined that the typical low

- bleed device available currently on the market emits lower than the maximum rate allocated for the device type

. Specifically, low

- bleed devices on the market today have emissions from 0.2 scf

h up to 5 scf

h

. Similarly, the available bleed rates for a high bleed device vary significant ly from venting as low as 7 scf h to as high as 100 scf

h. 3 , ii While the vendor data provides useful information on specific makes and models , it did not yield sufficient information about the

i The classification of high

- bleed and low

- bleed devices originated from a report by Pacific Gas & Electric (PG& E) and the Gas Research Institute (GRI) in 1990 titled “Unaccounted for Gas Project Summary Volume .” This classification was adopted for the October 1993 Report to Congress titled “Opportunities to Reduce Anthropogenic Methane Emissions in the United State s”. As described on page 2

- 16 of the report, “devices with emissions or „bleed‟ rates of 0.1 to 0.5 cubic feet per minute are considered to be „high

- bleed‟ types (PG&E 1990).” This range of bleed rates is equivalent to 6 to 30 cubic feet per hour. ii All ra tes are listed at an assumed supply gas pressure of 20 psig.5

- 4 Table 5

- 1 . Major Studies Reviewed for Consideration

of Emissions and Activity Data

Report Name Affiliation Year of Report Number of

Devices Emissions

Information Control

Information Greenhouse Gas Mandatory Reporting Rule and Technical Supporting Document 3 EPA 2010 Nationwide X

Inventory of Greenhouse Ga s Emissions and Sinks: 1990

- 2009 4 , 5 EPA 2011 Nationwide/ Regional X

Methane Emissions from the Natural Gas Industry 6 , 7 , 8 , 9 Gas Research Institute / EPA 1996 Nationwide X

Methane Emissions from the Petroleum Industry (draft) 10 EPA 1996 Nationwide X
Methane Emissions from the Petroleum Industry 11 EPA 1999 Nationwide X

Oil and Gas Emission Inventories for Western States 12 Western Regional Air Partnership 2005 Regional X

Natural Gas S TAR Program 1 EPA 2000

- 2010 X X5

- 5

prevalence of each model type in the population of devices ; which is an important factor in developing a representative emission factor. Therefore, f or this analysis, EPA determined that best available emissions estimates for pneumatic devices are presented in Table W

- 1A and W

- 1B of the Greenhouse Gas Mandatory Reporting Rule for the Oil and Natural Gas Industry (Subpart W)

. However, for the natural ga s processing segment, a more conservative approach was assumed since it has been determined that natural gas processing plants would have sufficient electrical service to upgrade to non

gas driven controls

. Therefore, to quantify representative emissions f rom a bleed

- device in the natural gas processing segment, information from Volume 12 of the EPA/GRI report iii was used to estimate the methane emissions from a single pneumatic device by type.
The basic approach used for this analysis was to first approxima te methane emissions from the average pneumatic device type in each industry segment and then estimate VOC and hazardous air pollutants (HAP) using a representative gas composition

. 13 The specific ratios from the gas composition were 0.278 pounds VOC per pound methane and 0.0105 pounds HAP per pound methane in the production and processing segments, and 0.0277 pounds VOC per pound methane and 0.0008 pounds HAP per pound meth ane in the transmission segment. Table 5

- 2 summarizes the estimated bleed emissions for a representative pneumatic controller by industry segment and device type

.

5.3 Nationwide Emissions from New Sources

5.3.1 Approach

Nationwide emissions from newly installed natural gas pneumatic devices for a typical year were calculated by estimating the number of pneumatic devices installed in a typical year and multiplying by the estimated annual emission s per device listed in Table 5

- 2

. The number of new pneumatic devices installed for a typical year was determined for each segment of the industry including natural gas production, natural gas processing, natural gas transmission and storage, and oil production. The methodologies that determined the estimated number of new devices installed in a typical year is provided in section 5.3.2 of this chapter.

5.3.2 Population of Devices Installed Annually
In order to estimate the average number of pneumatic devices installed in a typical year, each industry

iii Table 4

- 11. page 56

. epa.gov/gasstar/tools/related.html5

- 6

Table 5

- 2

. Average Bleed Emission Estimates per Pneumatic Device in the Oil and Natural Gas Sector (tons/year) a

Industry Segment High

- Bleed Low

- Bleed Methane VOC HAP Methane VOC HAP
Natural Gas Production b 6.91 1.92 0.07 3 0.26 0.07 2 0.003

Natural Gas Transmission and Storage c 3.20 0.0 8 9 0.003 0.24 0.0 07 0.0002

Oil Production d 6.91 1.92 0.07 3 0.26 0.07 2 0.003

Natural Gas Processing e 1.00 0.28 0.01 1.00 0.28 0.01 Minor discrepancies may be due to rounding.
a. The conversion factor used in this analysis is 1 thousand cubic feet of methane (Mcf ) is equal to 0.0208 tons methane

. Minor discrepancies may be due to rounding. b. Natural Gas Production methane emission s are derived from Table W

- 1A and W

- 1B of Subpart W.
c. Natural gas transmission a nd storage methane emissions are derived from Table W

- 3 of Subpart W. d. Oil production methane emissions are derived from Table W

- 1A and W

- 1B of Subpart W. It is assumed only continuous bleed devices are used in oil production.
e. Natural gas processing sector methane emissions are derived from Volume 12 of the 1996 GRI report

. 9 Emissions from devices in the processing sector were determined based on data available for snap

- acting and bleed devices, further distinction between high and low bleed could not be determined based on available data.5

- 7

segment was analyzed separately using the best data available for each segment. T he number of facilities estimated in absence of regulation was undeterminable due to the magnitude of new sources estimated and the lack of sufficient data that could indicate the number of controllers that would be installed in states that may have regula tions requiring low bleed controllers, such as in Wyoming and Colorado.
For the natural gas production and oil production segments, t he number of new pneumatics installed in a typical year was derived using a multiphase analysis . First, d ata from the US G reenhouse Gas Invento ry: Emission and Sinks 1990

- 2009 was used to establish the ratio of pneumatic controllers installed per well site on a regional basis

. These ratios were then applied to the number of well completions estimated in Chapter 4 for natural gas well completions with hydraul ic fracturing, natural gas well completions without hydraulic fracturing and for oil well completions. On average, one pneumatic device was assumed to be installed per well completion for a total of 33 ,411 pneumatic devices. By applying the estimated 51 percent of bleed devices (versus snap acting controllers), it is estimated that an average of 17,040 bleed

- devices would be installed in the production segment in a typical year.
The number of pneumatic controllers installed in the transmission segment was approximated using the
Inventor y of U.S. Greenhouse Gas Emissions and Sinks : 1990

- 2009. The number of new devices installed in a given year was estimated by subtracting the prior year (e.g. 2007) from t he given year‟s total (e.g. 2008). This difference was assumed to be the number of new devices installed in the latter year (e.g. Number of new devices installed during 2008 = Pneumatics in 2008

– Pneumatics in 2007). A 3

- year average was calculated based on the number of new devices installed in 2006 through 2008 in order to determine the average number of new devices installed in a typical year

.

Once the population counts for the number of pneumatics in each segment were established, this population coun t was further refined to account for the number of snap

- acting devices that would be installed versus a bleed device. This estimate of the percent of snap

- acting and bleed devices was based on raw da ta found in the GRI study, where 51 percent of the pneuma tic controllers are bleed devices in the production segment, and 32 percent of the pneumatic controllers are bleed devic es in the transmission segment. 9 The distinction between the number of high

- bleed and low

- bleed devices was not estimated because this analysis assumes it is not possible to predict or ensure where low bleeds will be used in the future. Table 5

- 3 summarizes the estimated number o f new devices installed per year.5

- 8

Table 5

- 3

. Estimated Number of Pneumatic Devices Installed in an Typical Year
Industry Segment Number of New Devices Estimated for a Typical Year a Snap

- Acting Bleed

- Devices Total
Natural Gas and Oil Production b 16,371 17,040 33,411

Natural Gas Transmission and

Storage c 178 84 262

a. National averages of population counts from the Inventory were refined to include the difference in snap

- acting and bleed devices based on raw data found in the GRI/EPA study

. This is based on the assumption that 51 percent of the pneumatic controllers are bleed devices in the production segment , while 32 percent are bleed devices in the transmission segment. b. The number of pneumatics was derived from a multiphase analysis

. Data from the US G reenhouse Gas Inventory: Emission and Sinks 1990

- 2009 was used to establish the number of pneumatics per well on a regional basis

. These ratios were applied to the number of well completions estimated in Chapter 4 for natural gas wells with hydraulic fract uring, natural gas wells without hydraulic fracturing and for oil wells.
c. The number of pneumatics estimated for the transmission segment was approximated from comparing a 3 year average of new devices installed in 2006 through 2008 in order to establish
a n average number of pneumatics being installed in this industry segment in a typical year

. This analysis was performed using the Inventor y of U.S. Greenhouse Gas Emissions and Sinks: 1990

- 2009

.5

- 9

For the natural gas processing segment, this analysis assumes that existing natural gas plants have already replaced pneumatic controllers with other types of controls (i.e. an instrument air system) and any high

- bleed devices that remain are safety relate d. As a result, the number of new pneumatic bleed devices installed at existing natural gas processing plants was estimated as negligible. A new greenfield natural gas processing plant would require multiple control loops. In Chapter 8 of this document, it is estimated that 29 new and existing processing facilities would be subject to the NSPS for equipment leak detection. In order to quantify the impacts of the regulatory options represented in section 5.5 of this Chapter, i t is assumed that half of these facilities are new sites that will install an instrument air system in place of multiple control valves. This indicates about 15 instrument air systems will be installed in a representative year

.

5.3.3 Emission Estimates

Nationwide baseline emission estim ates for pneumatic devices for new sources in a typical year are summarized in Table 5

- 4 by industry segment and device type. This analysis assumed for the nationwide emission estimate that all bleed

- devices have the high

- bleed emission rates estimated in Table 5

- 2 per industry segment since it cannot be predicted which sources would install a low bleed versus a high bleed controller.

5.4 Control Techniques
Although pneumatic devices have relatively small emissions individually , due to the large population of these devices installed on an annual basis, the cumulative VOC emissions for the industry are significant

. As a result, several options to reduce emissions have been developed over the years . Table 5

- 5 provides a summary of these options for reducing e missions from pneumatic devices including : instrument air, non

- gas driven controls, and enhanced maintenance

. Given the various control options and applicability issues, the replacement of a high

- bleed with a low

bleed device is the most likely scenario f or reducing emissions from pneumatic device emissions

. This is also supported by States such as Colorado and Wyoming that require the use of low

- bleed controllers in place of high

- bleed controllers. Therefore, l ow

- bleed devices are further described in the following section , along with estimates of the impacts of their application for a representative device and nationwide basis. Although snap

- acting devices have zero bleed emissions, this analysis assumes the5

- 10

Table 5

- 4 . Nationwide Baseline Emissions from Representative Pneumatic Device Installed in a Typical Year for the Oil and Natural Gas Industry (tons/year) a

Industry Segment Baseline Emissions from

Representative New Unit

(tpy) Number of

New Bleed Devices Expected Per Year Nationwide Baseline

Emissions from Bleeding Pneumatic (tpy) b
VOC Methane HAP VOC Methane HAP
Oil and Gas Production 1.92 13 6.91 12 0.0725 17,040 32,739 117,766 1,237
Natural Gas Transmission and Storage 0.09523 3. 423 0.003 84 8 288 0.2
Minor discrepancies may be due to rounding.
a. Emissions have been based on the bleed rates for a high

- bleed device by industry segment. Minor discrepancies may be due to rounding. b. To estimate VOC and HAP, weight ratios were developed based on methane emissi ons per device. The specific ratios used were 0.278 pounds VOC per pound methane and 0.0105 pounds HAP per pound methane in the production and processing segments, and 0.0277 pounds VOC per pound methane and 0.0008 pounds HAP per pound methane in the trans mission segment.5

- 11 Table 5

- 5

. Alternative Control Options for Pneumatic Devices

Option Description Applicability/Effectiveness Estimated Cost Range Install Low Bleed Device in Place of High Bleed Device Low

- bleed devices provide the same functional control as a

high

- bleed device, while emitting less continuous bleed emissions. Applicability may depend on the function of instrumentation for an individual device on whether the device is a level, pressure, or temperature controller. Lo w

- b leed devices
are , on average , around $165 more than high bleed version s

. Convert to Instrument Air 14 Compressed air may be substituted for natural gas in pneumatic

systems without altering any of the parts of the pneumatic control

. In this type of system, atmospheric air is compressed, stored in a tank, filtered and then dried for instrument use

. For utility purposes such as small pneumatic pumps, gas compressor motor starters, pneumatic tools and sand blasting, air would n ot need to be dried

. Instrument air conversion requires additional equipment to properly compress and control the pressured air

. This equipment includes a compressor, power source, air dehydrator and air storage vessel. Replacing natural gas with instrument air in pneumatic controls eliminates VOC emissions from bleeding pneumatics

. It is most effective at f acilities where there are a high concentration of pneumatic control valves and
a n operator present

. Since the system s are powered by electric compressors, they require a constant source of electrical power or a back

up natural gas pneumatic device. These systems can achieve 100 percent reduction in emissions. A c omplete cost analysis is provided in Sect ion 5.4.2. Syste m cost s are dependent on size of compressor, power supply needs, labor and other equipment.

Mechanical and Solar Powered Systems in place of Bleed device 15 Mechanical controls operate using a simple design comprised of

levers, hand wheels, springs and flow channels

. The most common mechanical control device is the liquid

- level float to the drain valve position with mechanical linkages

. Electricity or small electrical motors (including solar powered) have been used to operate valves. Solar control system s are driven by solar power cells that actuate mechanical devices using electric power. As such, solar cells require some type of back

- up power or storage to ensure reliability. Application of mechanical controls is limited because the control must be loca ted in close proximity to the process measurement

. Mechanical systems are also incapable of handling larger flow fluctuations

. Electric powered valves are only relia ble with a constant supply of electricity

. Overall, these option s are applicable in niche a reas but can achieve 100 percent reduction in emissions where applicable. Depending on supply of power, costs can range from below $1,000 to $10,000 for entire systems.

Enhanced Maintenance 16 Instrumentation in poor condition typically bleeds 5 to 10 scf

per hour more than representative conditions due to worn seals, gaskets, diaphragms; nozzle corrosion or wear, or loose control tube fittings

. This may not impact the operations but does increase emissions. Enhanced maintenance to repair and maintain pneu matic devices periodically can reduce emissions

. Proper methods of maintaining a device are highly variable and could incur significant costs. Variable based on labor, time, and fuel required to travel to many remote locations.5

- 12

de vices are not always used in the same functional application as bleed devices and are, therefore, not an appropriate form of control for all bleed devices . It is assumed snap

- acting, or no

- bleed, devices meet the definition of a low

- bleed. This concept is further detailed in Section 5.5 of this chapter. Since this analysis has assumed areas with electrical power have already converted applicable pneumatic devices to instrument air systems, instrument air system s are also described for natural gas processing plants only. Given applicability, efficiency and the expected costs of the other options identified in Table 5

- 5 (i.e. mechanical controls and enhanced maintenance) , were not further conducted for this analys is.

5.4.1 Low

- Bleed Controllers

5.4.1.1 Emission Reduction Potential

A s discussed in the above sections, low

- bleed devices provide the same functional control as a high

bleed device, but have l ower continuous bleed emissions. As summarized in Table 5

- 6, i t is estimated on average that 6.6 tons of methane and 1.8 tons of VOC will be reduced annually in the production segment from installing a low

- bleed device in place of a high

- bleed device. In the transmission segment, the average achievable reductions per device are estimated around 3.7 tons and 0.08 tons for methane and VOC, respectively . As noted in section 5.2, a low

- bleed controller can emit up to 6 scfh, which is higher than the expected emissions from the typical low

- bleed device available on the cur rent market.

5.4.1.1 Effectiveness
There are certain situations in which replacing and retrofitting are not feasible, such as instances where a minimal response time is needed, cases where large valves require a high bleed rate to actuate, or a safety iso lation valve is involved. Based on criteria provided by the Natural Gas STAR Program, it is assumed about 80 percent of high

- bleed devices can be replaced with low

- bleed devices throughout the production and transmission and storage industry segments

. 1 This corresponds to 13,632 new high

- bleed devices in the production segment (out of 17,040) and 67 new high

- bleed devices in the transmission and storage seg ment (out of 84) that can be replaced with a new low

- bleed alternative. For high

- bleed devices in natural gas processing, this analysis assumed that the replaceable devices have already been replaced with instrument air and the remaining high

- bleed devices are safety related for about half of the existing processing plants

.5

- 13

Table 5

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

Bleed Pneumatic Device with a Representative Low

- Bleed Pneumatic Device

Segment/Device Type Emissions (tons/year) a Methane VOC HAP Oil and Natural Gas Production 6.65 1.85 0.07 Natural Gas Transmission and Storage 2.96 0.082 0.002 Minor discrepancies may be due to rounding.
a. Average emission reductions for each industry segment based on the typical emission flow rates from high

- bleed and low

- bleed devices as listed in Table 5

- 2 by industry segment

.5

- 14

Applicability may depend on the function of instrumentation for an individual device on whether the device is a level, pressure, or temperature controller

. High

- bleed pneumatic devices may not be applicable for replacement with low

- bleed devices because a process condition may require a fast or precise control response so that it does not stray too far from the desired set point. A slower

- acting controller could potentially result in damage to equipment and/or become a safety issue. An example of this is on a compressor where pneumatic devices may monitor the suction an d discharge pressure and

actuate a re

- cycle when one or the other is out of the specified target range. Other scenarios for fast and precise control include transient (non

- steady) situations where a gas flow rate may fluctuate widely or unpredictably. This situation requires a r esponsive high

- bleed device to ensure that the gas flow can be controlled in all situations

. Temperature and level controllers are typically present in control situations that are not prone to fluctuate as widely or where the fluctua tion can be readily and safely accommodated by the equipment . Therefore, such processes can accommodate con trol from a low

- bleed device, which is slower

- acting and less precise.
Safety concerns may be a limitation issue, but only in specific situations because e mergency valves are not bleeding controllers since safety is the pre

- eminent consideration

. Thus, the connection between the bleed rate of a pneumatic device and safety is not a direct one

. Pneumatic devices are designed for
process co ntrol during normal operations and to keep the process in a normal operating state

. If an Emergency Shut Down (ESD) or Pressure Relief Valve (PRV) actuation occurs , iv the equipment in place for such an event is spring loaded , or otherwise not pneumatically powered

. During a safety issue or emergency, it is possible that the pne umatic gas supply will be lost. For this reason, control valves are deliberately selected to either fail open or fail closed, depen ding on which option is the failsafe.

5.4.1.2 Cost Im

pacts

As described in Section 5.2.2, c osts were based on the vendor research described in Section 5.2 as a result of updating and expanding upon the information given in the appendices of the Natural Gas STAR Lessons Learned document on pneumatic devices

. 1 As Table 5

- 7 indicates, the average cost for a low bleed pneumatic is $2,553, while the average cost for a high bleed is $2,338. v Thus , the incremental cost of installing a low

- bleed device instead of a high

- bleed device is on the order of $165 per device

. In order to analyze cost impacts, the in cremental cost to install a low

- bleed instead of a high

- bleed was

iv ESD valves either close or open in an emergency depending on the fail safe configuration

. PRVs always open in an emergency

. v Costs are estimated in 2008 U.S. Dollars.5

- 15 Table 5

- 7 . Cost Projections for the Representative Pneumatic Devices a

Device Minimum

cost ($) Maximum

cost ($) Average cost ($) Low

- Bleed Incremental Cost ($) High

- bleed controller 366 7,000 2,388 $165 Low

- bleed controller 524 8,852 2,553

a. Major pneumatic devices vendors were surveyed for costs, emission rates, and any other pertinent information that would give an accurate picture of the present industry.5

- 16

annualized for a 10 year period using a 7 percent interest rate. This equated to an annualized cost of around $23 per device for both the production and transmission segments.

Monetary savings associated with additional gas captured to the sales line was estimated based on a natural gas value of $4.00 per Mcf. vi , 17 The representative low

- bleed device is estimated to emit 6.65 tons, or 319 Mcf, (using the conversion factor of 0.0208 tons methane per 1 Mcf) of methane less than the average high

- bleed device per year. As suming production quality gas is 82. 8 percent methane by volume, this equals 385.5 Mcf natural gas recovered per year. Therefore, t he value of recovered natural gas from one pneumatic device in the production segment equates to approximately $1,500

. Saving s were not estimated for the transmission segment because it is assumed the owner of the pneumatic controller generally is not the owner of the natural gas

. Table 5

- 8 provides a summary of low

- bleed pneumatic cost effectiveness.

5.4.1.3 Secondary Impacts

Low

- bleed pneumatic devices are a replacement option for high

- bleed devices that simply bleed less natural gas that would otherwise be emitted in the actuation of pneumatic valves. No wastes should be created, no wastewater generated, and no electricity ne eded. Therefore, there are no secondary impacts expected due to the use of low

- bleed pneumatic devices.
5.4.2 Instrument Air Systems

5.4.2.1 Process Description
The major components of an instrument air conversion project include the compressor, power sou rce, dehydrator, and volume tank

. The following is a description of each component as described in the Natural Gas STAR document, Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air :

 Compressors used for instrument air delivery are available in various type s and sizes, from centrifugal (rotary screw) compressors to reciprocating piston ( positive displacement) types

. The size of the compressor depends on the size of the facility, the number of control devices operated by the system, and the typical bleed rates of these devices

. The compressor is usually driven by an electric motor that turns on and off, depending on the pressure in the volume tank.

vi The average market price for natural gas in 20 10 was approximately $4.16 per M cf

. Th is is much less compared to the
aver age price in 2008 of $7.96 per M cf

. Due to the volatility in the value , a con servative savings of $4.00 per M cf estimate was projected for the analysis in order to not overstate savings

.5

- 17 Table 5

- 8. Cost

- effectiveness for Low

- Bleed Pneumatic Devices

versus High Bleed Pneumatics

Segment Incremental

Capital Cost Per Unit ($) a Total Annual Cost

Per Unit ($/yr) b VOC Cost

Effectiveness ($/ton) Methane Cost

Effectiveness ($/ton) without savings with

savings without

savings with

savings without

savings with

savings Oil and Natural Gas Production 165 23.50

- 1,519 13 net savings 4 net

savings
Natural Gas Transmission and Storage 165 23.50 23.50 286 286 8 8

a. Incremental cost of a low bleed device versus a high bleed device as summarized in Table 5

- 7. b. Annualized cost assumes a 7 percent interest rate over a 10 year equipment lifetime.5

- 18

For reliability, a full spare compressor is normally installed. A minimum amount of electrical service is required to power the compressors.

 A critical component of the instrument air control system is the power source required to operate the compressor. Since high

- pressure natural gas is abundant and readily available, gas pneumatic systems can run uninterrupted on a 24

- hour, 7

- day per week schedule. The reliability of an instrument air system, however, depends on the reliability of the compressor and electric power supply. Most large natural gas plants have either an e xisting electric power supply or have their own power generation system. For smaller facilities and in remote locations, however, a reliable source of electric power can be difficult to assure. In some instances, solar

- powered battery

- operated air compress ors can be cost effective for remote locations, which reduce both methane emissions and energy consumption. Small natural gas powered fuel cells are also being developed.

 Dehydrators, or air dryers, are also an integral part of the instrument air compressor system

. Water vapor present in atmospheric air condenses when the air is pressurized and cooled, and can cause a number of problems to these systems, including corrosion of the instrument parts and blockage of instrument air piping and controlle r orifices

.

 The volume tank holds enough air to allow the pneumatic control system to have an uninterrupted supply of high pressure air without having to run the air compressor continuously

. The volume tank allows a large withdrawal of compressed air for a short time, such as for a motor starter, pneumatic pump, or pneumatic tools, without affecting the process control functions.

Compressed air may be substituted for natural gas in pneumatic systems without altering any of the parts of the pneumatic contro l. The use of instrument air eliminates natural gas emissions from natural gas powered pneumatic controllers. All other parts of a gas pneumatic system will operate the same way with instrument air as they do with natural gas. The conversion of natural gas pneumatic controllers to instrument air systems is applicable to all natural gas facilities with electrical service available. 14

5.4.2.2 Effectiveness

The us e of instrument air eliminates natural gas emissions from the natural gas driven pneumatic devices; however, the system is only applicable in locations with access to a sufficient and consistent5

- 19

supply of electrical power

. Instrument air systems are also u sually installed at facilities where there is a high concentration of pneumatic control valves and the presence of an operator that can ensure the system is properly functioning

. 14

5.4.2.3 Cost Impacts
Instrument air conversion requires additional equipment to properly compress and control the pressured air. T he size of the compressor will depend on the number of contr ol loops present at a location . A control loop consists of one pneumatic controller and one control valve. The volume of compress ed air supply for the pneumatic system is equivalent to the volume of gas used to run the existing instrumentation

– adjusted f or air losses during the drying process. The current volume of gas usage can be determined by direct metering if a meter is installed. Otherwise, an alternative rule of thumb for sizing instrument air systems is one cubic foot per minute (cfm) of instrumen t air for each control loop. 14 As the system is powered by electric compressors, the system requires a constant source of electrical power or a back

- up pneumati c device. Table 5

- 9 outlines three different sized instrument air systems including the compressor power requirements, the flow rate provided from the compressor, and the associated number of control loops.
The primary costs associated with conversion to i nstrument air systems are the initial capital expenditures for installing compressors and related equipment and the operating costs for electrical energy to power the compressor motor. This equipment includes a compressor, a power source, a dehydrator and a storage vessel. It is assumed that in either an instrument air solution or a natural gas pneumatic solution, gas supply piping, control instruments, and valve actuators of the gas pneumatic system are required . 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: Convert Gas Pneumatic Controls to Instrument Air” 14 and summarized in Table 5

- 10. vii

For natural gas processing, the cost

- effectiveness of the three representative instrument air system sizes was evaluated based on the emissions mitigated from the number of control loops the syste m can provide and not on a per device basis. This approach was chosen because we assume new processing plants will need to provide instrumentation of multiple control loops and size the instrument air system accordingly. We also assume that existing processing plants have already upgraded to instrument air

vii Costs have been converted to 2 008 US dollars using the Chemical Engineering Cost Index.5

- 20

Table 5

- 9. Compressor Power R equirements and Costs for Various Sized Instrument Air Systems a

Compressor Power Requirements b Flow Rate Control Loops Size of Unit hp kW (cfm) Loops/Compressor 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 14 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).5

- 21 Table 5

- 10 Estimated Capit al and Annual Cost s of Various Sized Representative Instrument Air Systems

Instrument Air System Size Compressor Tank Air Dryer Total Capital a Annualized

Capital b Labor

Cost Total

Annual Costs c Annualized Cost

of Instrument Air System Small $3,772 $754 $2,262 $16,972 $2,416 $1,334 $8,674 $ 11,090 M edium $18,855 $2,262 $6,787 $73,531 $ 10,469 $4,333 $26,408 $ 36,877 Large $33,183 $4,525 $15,083 $135,750 $ 19,328 $5,999 $61,187 $ 80,515

a. Total Capital includes the cost for two compressor s , tank , an air dryer and i nstallation . Installation costs are assumed to be equal to 1.5 times the cost of capital. Equipment costs were derived from the Natural Gas Star Lessons Learned document and converted to 2008 dollars from 2006 dollars using the Chemical Engineering Cost Index. b. The annualized cost was estimated using a 7 percent interest rate and 10 year equipment life.
c. Annual Costs include the co st of electrical power as listed in Table 5

- 9 and labor.5

- 22

unless the function has a specific need for a bleeding device, which would most likely be safety related. 9
Table 5

- 11 summarizes the cost

- effectiveness of the three s izes of representative instrument air systems.

5.4.2.4 Secondary Impacts
The secondary impacts from i nstrument a ir s ystems are indirect, variable and dependent on the electrical supply used to power the compressor. No other secondary impacts are expected.

5.5 Regulatory Options
The affected facility definition for pneumatic controllers is defined as a single natural gas pneumatic controller

. Therefore, pneumatic controllers would be subject to a New Sourc e Performance Standard (NSPS) at the time of installation. The following Regulatory alternatives were evaluated:

 Regulatory Option 1 : Establish an emissions limit equal to 0 scfh.

 Regulatory Option 2: Es tabli sh an emissions limit equal to 6 scfh.
5.5.1 Evaluation of Regulatory Options
By establishing an emission limit of 0 scfh, facilities would most likely install instrument air systems to meet the threshold limit. This option is considered cost effectiv e for natural gas processing plants as summarized in Table 5

- 11. A major assumption of this analysis, however, is that processing plant s are constructed at a location with sufficient electrical service to power the instrument air compression system. It is assumed that facilities located outside of the processing plant would not have sufficient electrical service to install an instrument air system. This would significantly increase the cost of the system at these locations, making it not cost effective for these facilities to meet this regulatory option. Therefore, Regulatory Option 1 was accepted for natural gas processing plants and rejected for all other types of facilities.
Regulatory Option 2 would establish an emission limit equal to the maximum emissions allowed for a low

- bleed device in the production and transmissions and storage industry segments. This would most likely be met by the use of low

- bleed controllers in place of a high

- bleed controller, but allows flexibility in the ch osen method of meeting the requirement. In the key instances related to pressure control that would disallow the use of a low

- bleed device, specific monitor ing and recordkeeping criteria5

- 23 Table 5

- 11 Cost

- effectiveness of Representative Instrument Air Syste ms in the Natural Gas Processing Segment

System Size Number of

Control Loops Annual Emissions

Reduction a (tons/year) Value of Product Recovered ($/year) b Annualized Cost of

System VOC Cost

effectiveness ($/ton) Methane Cost

effectiveness ($/ton)

VOC CH 4 HAP without savings with

savings without

savings with

savings without

savings with

savings
Small 15 4.18 15 0.16 3,484 11,090 7,606 2,656 1,822 738 506 Medium 63 17.5 63 0.66 14,632 36,877 22,245 2,103 1,269 585 353 Large 175 48.7 175 1.84 40,644 80,515 39,871 1,653 819 460 228 Minor discrepancies may be due to rounding

. 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. 8 percent methane by volume

. A natural gas price of $4 per Mcf was assumed.5

- 24

w ould be required to ensure the device function dictates the precision of a high bleed device . Therefore,
R egulatory O ption 2 was accepted for locations outside of natural gas processing plants.

5.5.2 Nationwide Impacts of Regulatory Options

Table 5

- 12 summarizes the costs impacts of the selected regulatory options by industry segment

. Regulatory Option 1 for the natural gas process ing segment is estimated to affect 15 new processing plants with nationwide annual costs discounting savings of $166, 000

. When savings are realized the net annual cost is reduced to around $114,000. Regulatory Option 2 has nationwide annual cos ts of $320,000 for the production segment and around $1,500 in the natural gas transmission and storage segment. When annual savings are realized in the production segment there is a net savings of $20.7 million in nationwide annual costs.5

- 25

T able 5

- 12 Nationwide Cost and Emission Reduction Impacts for Selected Regulatory Options by Industry Segment

Industry Segment Number

of Sources subject to NSPS* Capital Cost

Per Device/IAS ($)** Annual Costs

($/year) Nationwide Emissio n

Reductions (tpy)† VOC Cost Effectiveness ($/ton) Methane Cost

Effectiveness ($/ton) Total Nationwide Costs ($/year)

without savings with

savings VOC Methane HAP without savings with

savings without

savings with

savings Capital

Cost Annual

without savings Annual with

savings
Regulatory Option 1 (emission threshold equal to 0 scfh)

Natural Gas Processing 15 16,972 11,090 7,606 63 225 2 2,656 1,822 738 506 254,576 166,351 114,094

Re gulatory Option 2 (emission threshold equal to 6 scfh) Oil and Natural G as Production 13,632 165 23 ( 1,519 ) 25,210 90,685 952 13 net savings 4 net

savings 2,249,221 320,071 (20, 699,918 )

Natural Gas Transmission and Storage 67 165 23 23 6 212 0 .2 262 262 7 7 11,039 1,539 1,539

Mi nor discrepancies may be due to rounding.
a. The number of sources subject to NSPS for the natural gas processing and the natural gas transmission and storage segments re present the number of new devices expected per year reduced by 20 percent. This is consi stent with the assumption that 80 percent of high bleed devices can be replaced with a low bleed device. It is assumed all new sources would be installed as a high bleed for t hese segments. For the natural gas processing segment the number of new sources r epresents the number of Instrument Air Systems (IAS) that is expected to be installed, with each IAS expected to power 15 control loops (or replace 15 pneumatic devices). b. The capital cost for regulatory option 2 is equal to the incremental cost of a low b leed device versus a new high bleed device. The capital cost of the IAS is based on the smal l IAS as summarized in Table 5

- 10

. c. Nationwide emission reductions vary based on average expected emission rates of bleed devices typically used in each segment ind ustry segment as summarized in Tables 5

- 2.5

- 26

5.6 References

1 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 Sta r. Washington, DC. February 2004

2 Memorandum to Bruce Moore from Denise Grubert

. Meeting Minutes from EPA Meeting with the American Petroleum Institute

. October 2011

3 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.

4 U.S Environmental Protection Agency. Met hodology for Estimating CH4 and CO2 Emissions from Natural Gas Systems. Greenhouse Gas Inventory: Emission and Sinks 1990

- 2008. Washington, DC.

5 U.S Environmental Protection Agency. Methodology for Estimating CH 4 and CO 2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 1990

- 2008. Washington, DC.

6 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 2: Technical Report. Prepared for the Gas Research Institute and Environmental Protection Agency. EP A

600/R

- 96

- 080b. June 1996.

7 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 3: General Methodology. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA

- 600/R

- 96

- 080c. June 1996.

8 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.

9 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. J une 1996.

10 Radian International LLC, Methane Emissions from the U.S. Petroleum Industry , draft report for the U.S. Environmental Protection Agency, June 14, 1996.

11 ICF Consulting. Estimates of Methane Emissions from the U.S. Oil Industry. Prepared for the U.S. Environmental Protection Agency. 1999.

12 ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States. Prepared for Western Governors‟ Association. December 27, 2005.

13 Memorandum to Bruce Moore from Heather Brown. Gas Composition Methodology. July 20115

- 27

14 U.S. Environmental Protection Agency. Lessons Learned: Convert G as Pneumatic Controls to Instrument Air . Office of Air and Radiation: Natural Gas Star. Washington, DC. February 2004

15 U.S. Environmental Protection Agency. Pro Fact Sheet No. 301. Convert Pneumatics to Mechanical Controls. Office of Air and Radiation: N atural Gas Star. Washington, DC. September 2004.

16 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.

17 U.S. Energy Information Admi nistration. 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>6

- 1 6 .0 COMPRESSORS
Compressors are mechanical devices that increase the pressure of natural gas and allow the natural gas to be transported from the production site , th r ough the supply chain, and to the consumer

. The types of compressors that are used by the oil and gas industry as prime movers are r eciprocating and centrifugal
compressors

. This chapter discusses the air pollutant emissions from these compressors and provides emission estimates for reducing emission from these types of compressors

. In additio n, nationwide emission s estimates from new sources are estimated

. Options for controlling pollutant emissions from these compressors are presented, along with costs, emission reductions, and secondary impacts

. Finally, this chapter discusses considerations in developing regulatory alternatives for both reciprocating and centrifugal compressors

.

6 .1 Process Description

6 .1.1 Reciprocating Compressors
In a reciprocating compressor, natural gas enters the suction manifold, and then flows into a compression cyl inder where it is compressed by a piston driven in a reciprocating motion by the crankshaft powered by an internal combustion engine

. Emissions occur when natural gas leaks around the piston rod when pressurized natural gas is in the cylinder

. The compress or rod packing system consists of a series of flexible rings that create a seal around the piston rod to prevent gas from escaping between the rod and the inboard cylinder head

. However, over time , during operation of the compressor, the rings become worn a nd the packing system will need to be replaced to prevent excessive leaking from the compression cylinder

.

6 .1.2 Centrifugal Compressors
Centrifugal compressors use a rotating disk or impeller to increase the velocity of the gas where it is directed to a divergent duct section that converts the velocity energy to pressure energy

. These compressors are primarily used for continuous, stationary transport of natural gas in the processing and transmission systems

. Many centrifugal compressors use wet (meaning oil) seals around the rotating shaft to prevent natural gas from escaping where the compressor shaft exits the compressor casing

. The wet seals use oil which is circulated at high pressure to form a barrier against compressed natural gas leakage

. T he circu lated oil entrains and absorbs some compressed natural gas which is released to the6

- 2

atmosphere during the seal oil recirculation process

. Alternatively, dry seals can be used to replace the wet seals in centrifugal compressors

. Dry seals prevent leakage by using the opposing force created by hydrodynamic groves and springs

. The opposing force screate a thin gap of high pressure gas between the rings th rough which little gas can leak. The rings do not wear or need lubrication because the y are not in contact w ith each other

. Therefore, operation and maintenance costs are lower for dry seals in comparison to wet seals.

6 .2 Emissions Data and Emission Factors

6 .2.1 Summary of Major Studies and Emissions Factors

There are a few studies that have been conducted tha t provide leak estimates from reciprocating and centrifugal compressors

. These studies are provided in Table 6

- 1 , along with the type of information contained in the study

.

6 .2.2 Representative Reciprocating and Centrifugal Compressor Emissions

The method ology for estimating emission from reciprocating compressor rod packing was to use the methane emission factors referenced in the EPA/GRI study 1 and use the methane to pollutant ratios developed in the gas composition memorandum. 2 The emission factors in the EPA/GRI document were expressed in thousand standard cubic feet per cylinder (Mscf/cyl), and were multiplied by the aver a ge number of cylinder per reciprocating compressor at each oil and gas industry segment

. The volumetric methane emission rate was c onverted to a mass emission rate using a density of 41.63 pounds of methane per thousand cubic feet

. This conversion factor was developed assuming that methane is an ideal gas and using the ideal gas law to calculate the density

. A summary of the methane e mission factors is presented in Table 6

- 2

. Once the methane emissions were calculated, ratios were used to estimate volatile organic compounds (VOC) and hazardous air pollutants (HAP)

. The specific ratios that were used for this analysis were 0.278 pounds VOC per pound of methane and 0.105 pounds HAP per pound of methane for the production and processing segments, and 0.0277 pounds VOC per pound of methane and 0.0008 pounds HAP per pound of methane for the transmission and storage segments

. A summary of the reciprocating compressor emissions are presented in Table 6

- 3.
The compressor emission factors for wet seals and dry seals are based on data used in the GHG inventory. The wet seals methane emission factor was calculated based on a sampling of 48 wet seal centrifugal compressors. The dry seal methane emission factor was based on data collected by the6

- 3 Table 6

- 1

. Major Studies Reviewed for Consideration

Of Emissions and Activity Data

Report Name Affiliation Year of Report Activity

Information Emissions

Information Control

Information

Inventory of Greenhouse Gas Emissions and Sinks: 1990

- 2008 1 EPA 2010 Nationwide X

Greenhouse Gas Mandatory Reporting Rule and Technical Supporting Document 2 EPA 2010 Nationwide X

Methane Emissions from the Natural Gas Industry 3 Gas Research Institute/ EPA 1996 Nationwide X

Natural Gas STAR Program

4,5 EPA 1993

- 2010 Nationwide X X6

- 4

Table 6

- 2

. Methane Emission Factors for Reciprocating and Centrifugal Compressors

Oil and Gas Industry Segment Reciprocating Compressors Centrifugal Compressors

Methane Emission Factor (scf/hr

- cylinder ) Average

Number of Cylinders Pressurized

Factor (% of h ou r/y ea r Compressor Pressurized) Wet Seal

Methane Emission Factor (scf/min ute ) Dry Seals

Methane Emission Factor (scf/min ute )

Production (Well Pads) 0.271 a 4 100% N/A f N/A f

Gathering & Boosting 25.9 b 3.3 79.1% N/A f N/A f

Processing 57 c 2.5 89.7% 47.7 g 6 g

Transmission 57 d 3.3 79.1% 47.7 g 6 g

Storage 51 e 4.5 67.5% 47.7 g 6 g

a. EPA/GRI. (1996). “Methane Emissions from the Natural Gas Industry: Volume 8

– Equipment Leaks.” Table 4

- 8

. b. 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.
c. E PA/GRI. (1996). Methane Emissions from the Natural Gas Industry: Volume 8

– Equipment Leaks

. Table 4

- 14

. d. EPA/GRI. (1996). “Methane Emissions from the Natural Gas Industry: Volume 8

– Equipment Leaks.” Table 4

- 17

. e. EPA/GRI. (1996). “Metha ne Emissions from the Natural Gas Industry: Volume 8

– Equipment Leaks.” Table 4

- 24

. f. The 1996 EPA/GRI Study Volume 11 3 , does not report any centrifugal compressors in the production or gathering/boosting sectors, therefore no emission factor data were pu blished for those two sectors. g. U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks1990

- 2009. Washington, DC. April 2011

. Annex 3. Page A

- 153

.6

- 5

Table 6

- 3

. Baseline Emission Estimates for Reciprocating and Centrifugal Compressors

Industry Segment / Compressor Type Baseline Emission Estimates (tons/year)

Methane VOC HAP
Reciprocating Compressors Production (Well Pads) 0.198 0.0549 0.00207 Gathering & Boosting 12.3 3.42 0.129 Processing 23.3 6.48 0.244
Transmission 27.1 0.751 0.0223 Storage 28.2 0.782 0.0232 Centrifugal Compressors (Wet seals) Processing 228 20.5 0.736
Transmission 126 3.50 0.104 Storage 126 3.50 0.104 Centrifugal Compressors (Dry seals) Processing 28.6 2.58 0.0926
Transmission 15.9 0.440 0.0131 Storage 15.9 0.440 0.01316

- 6

Natural Gas STAR Program. The methane emissions were converted to VOC and HAP emissions using the same gas composition ratios that were used for reciprocating engines. 4 A summary of the emission factors are presented in Table 6

- 2 and the individual compressor emission are shown in Table 6

- 3 for each of the oil and gas industry segments.

6 .3 Nationwide Emissions from New Sources

6 .3.1 Overview of Approach

The n umber of new affected facilities in each of the oil and gas sectors was estimated using data from the U.S. Greenhouse Gas Inventory , 5 , 6 with some exceptions

. This basis was used when ever the total number of existing facilities was explicitly estimated as part of the Inventory, so that the difference between two years can be calculated to represent the number of new facilities

. The Inventory was not used to estimate the new number of reciprocating compressor facilities in gas production , since more recent information is available in the comments received to subpart W of the mandatory reporting rule

. Similarly, the Inventory was not used to estimate the new number of reciprocating compressor facilities in gas gathering , since more recent informat ion is available in comments received as comments to subpart W of the mandatory reporting rule

. For both gas production and gas gathering, information received as comments to subpart W of the mandatory reporting rule was combined with additional EPA estima tes and assumptions to develop the estimates for the number of new affected facilities.

Nationwide emission estimates for new sources were then determined by multiplying the number of new sources for each oil and gas segment by the expected emissions per c ompressor using the emission data in Table 6

- 3

. A summary of the number of new reciprocating and centrifugal compressors for each of the oil and gas segments is presented in Table 6

- 4

.

6 .3. 2 Activity Data for Reciprocating Compressors

6 .3.2.1 Wellhead Reciprocating Compressors
The number of wellhead reciprocating compressors was estimated using data from industry comments on Subpart W of the Greenhouse Gas Mandatory Reporting Rule

. 7 The 2010 U.S. GHG Inventory reciprocating compressor activity data was not considered in the analysis because it does not distinguish between wellhead and gathering and boosting compressors

. Therefore, using data submitted to EPA during the s ubpart W comment perio d from nine basins supplied by the El Paso Corporation , 8 the6

- 7

Table 6

- 4

. Approximate N umber of New Sources in the Oil and Gas Industry in 2008

Industry Segment Number of New Reciprocating Compressors Number of New Centrifugal Compressors

Wellheads 6,000 0

Gathering and Boosting 210 0

Processing 209 16

Transmission 20 14 Storage 46

- 8

average number of new wellhead compressors per new well was calculated using the 315 well head compressors provided in the El Paso comments and 3,606 wells estimated in the Final Subpart W onshore production threshold analysis. This produced an average of 0.087 compressors per wellhead. The average wellhead compressors per well was multiplied by the total well completions (oil and gas) determined from the HPDI® database 9 between 2007 and 2008, which came to 68,000 new w ell completions. Using this methodology, the estimated number of new reciprocating compressors at production pads was calculated to be 6,000 for 2008. A summary of the number of new reciprocating compressors located at well pads is presented in Table 6

- 4.

6.3.2.2 Gathering and Boosting Reciprocating Compressors
The number of gathering & boosting reciprocating compressors was also estimated using data from industry comments on Subpart W. DCP Midstream stated on page 3 of its 2010 Subpart W comments that it o perates 48 natural gas processing plants and treaters and 700 gathering system compressor stations. Using this data, there were an average of 14.583 gathering and boosting compressor stations per processing plant. The number of new gathering and boosting c ompressors was determined by taking the average difference between the number of processing plants for each year in the 2010 U.S Inventory, which references the total processing plants in the Oil and Gas Journal. This was done for each year up to 2008. An average was taken of only the years with an increase in processing plants, up to 2008. The resulting average was multiplied by the 14.583 ratio of gathering and boosting compressor stations to processing plants and the 1.5 gathering and boosting compressor s per station yielding 210 new source gathering and boosting compressor stations and is shown in Table 6

- 4.

6 .3.2.3 Processing Reciprocating Compressors
The number of new processing reciprocating compressors at processing facilities was estimated by averaging the increase of reciprocating compressors at processing plants in the greenhouse gas inventory data for 2007, 2008, and 2009

. 10 , 11 The estimated number of existing reciprocating compressors in the processing segment was 4, 458 , 4,781, and 4 , 876 f or the years 2007, 2008, and 2009 respectively

. This calculated to be 323 new reciprocating compressors between 2007 and 2008, and 95 new reciprocating compressors between 2008 and 2009

. The average difference was calculated to be 209 reciprocating
compres sors and was used to estimate the number of new sources in Table 6

- 4

.6

- 9

6 .3.2.4 Transmission and Storage Reciprocating Compressors

The number of new transmission and storage reciprocating compressors was estimated u sing the differences in the greenhouse gas inventory 12 , 13 data for 2007, 2008, and 2009 and calculating an average of those differences

. The estimated number of existing reciprocating compressors at transmission stations was 7,158 , 7 , 028 , and 7 , 197 for the years 2007, 2008, and 2009 respectively

. This calculated to be

- 130 new reciprocating compressors between 2007 and 2008, and 169 new reciprocating compressors between 2008and 2009

. The average difference was calculated to be 20 reciprocating compressors and was used to estimate the number of new sources at transmission stations

. The number of existing reciprocating compressors at storage stations was 1,144 , 1,178, and 1,152 for the years 2007, 2008, and 2009 respectively

. This calculated to be 34 new reciprocating compressors between 2007 and 200 8, and

- 26 new reciprocating compressors between 2008and 2009

. The average difference was calculated to be 4 reciprocating compressors and was used to estimate the number of new sources at storage stations in Table 6

- 4

.

6 .3. 3 Activity Data for Centrifugal Compressors

T he number of new centrifugal compressors in 2008 for the processing and transmission/storage segments was determined by taking the average difference between the centrifugal compressor activity data for each year in the 2008 U.S. Inventory

. F or example, the number of compressors in 1992 was subtracted from the number of compressors in 1993 to determine the number of new centrifugal compressors in 1993

. This was done for each year up to 2008

. An average was taken of only the years with an incre ase in centrifugal compressors, up to 2008, to determine the number of new centrifugal compressors in 2008

. The result was 16 and 14 new centrifugal compressors in the processing and transmission segments respectively. A summary of the estimates for new ce ntrifugal compressor is presented in Table 6

- 4.

6 .3.4 Emission Estimates

Nationwide baseline emission estimates for new reciprocating and centrifugal compressors are
summarized in Table 6

- 5 by industry segment

.6

- 10

Table 6

- 5

. Nationwide Baseline Emissions fo r New Reciprocating and Centrifugal Compressors

Industry Segment / Compressor Type Nationwide baseline Emissions (tons/year)

Methane VOC HAP
Reciprocating Compressors Production (Well Pads) 1,186 330 12.4 Gathering & Boosting 2,587 719 27.1 Processing 4,871 1,354 51.0
Transmission 529 14.6 0.435 Storage 113 3.13 0.0929
Cen trifugal Compressors Processing 3,640 329 11.8 Transmission/Storage 1,768 48.9 1.456

- 11

6 .4 Control Techniques

6.4.1 Potential Control Techniques

The potential control options reviewed for reducing emissions from reciprocating compressors include control techniques that limit the leaking of natural gas past the piston rod packing. This includes replacement of the compressor rod packing, replacement of the piston rod, and the refitting or realignment of the piston rod.

The replacement of the rod packing is a maintenance task performed on reciprocating compressors to reduce the leakage of natural gas past the piston rod

. Over time the packing rings wear and allow more
natu ral gas to escape around the piston rod

. Regular replacement of these rings reduces methane and VOC emissions

. Therefore, this control technique was determined to be an appropriate optionfor reciprocating compressors.
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

. 14 Rods wear “out

- of

- round” or taper when poorly aligned, which affects the fit of packing rings against the shaft (and t herefore the tightness of the seal) and the rate of ring wear

. An out

- of

- round shaft not only seals poorly, allowing more leakage, but also causes uneven wear on the seals, thereby shortening the life of the piston rod and the packing seal

. Replacing or up grading the rod can reduce reciprocating compressor rod packing emissions

. Also, upgrading piston rods by coating them with tungsten carbide or chrome reduces wear over the life of the rod

. This analysis assumes operators will choose, at their discretion, when to replace the rod and hence, does not consider this control technique to be a practical control option for reciprocating compressors

. A summary of these techniques are presented in the following sections

. Potential control options to reduce emission s from centrifugal compressors include control techniques that limit the leaking of natural gas across the rotating shaft, or capture and destruction of the emissions using a flare

. A summary of these techniques are presented in the following sections.

A co ntrol technique for limiting or reducing the emission from the rotating shaft of a centrifugal compressor is a mechanical dry seal system

. This control technique uses rings to prevent the escape of natural gas across the rotating shaft

. This control technique was determined to be a viable option for reducing emission from centrifugal compressors.6

- 12

For c entrifugal compressors equipped with wet seals, a flare was consider ed to be a reasonable option for reducing emissions from centrifugal compressors

. Ce ntrifugal compressors require seals around the rotating shaft to prevent natural gas from escaping where the shaft exits the compressor casing

. “ B eam” type compressors have two seals, one on each end of the compressor, while “over

- hung” compressors have a seal on only the “inboard” ( motor end ) side

. These seals use oil, which is circulated under high pressure between three rings around the compressor shaft, forming a barrier against the compressed gas leakage

. The center ring is attached to the rotating sha ft, while the two rings on each side are stationary in the seal housing, pressed against a thin film of oil flowing between the rings to both lubricate and act as a leak barrier

. The seal also includes “O

- ring” rubber seals, which prevent leakage around th e stationary rings

. The oil barrier allows some gas to escape from the seal, but considerably more gas is entrained and absorbed in the oil under the high pressures at the “inboard” (compressor side) seal oil/gas interface, thus contaminating the seal oil

. Seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and recirculated back to the seal

. As a control measure, t he recovered gas would then be sent to a flare or other combustion device

.

6.4.2 Reciprocating Compres sor Rod Packing Replacement

6.4.2 .1 Description
Reciprocating compressor rod packing consists of a series of flexible rings that fit around a shaft to create a seal against leakage

. As the rings wear, they allow more compressed gas to escape, increasing

ro d packing emissions

. Rod packing emissions typically occur around the rings from slight movement of the rings in the cups as the rod moves, but can also occur through the “nose gasket” around the packing case, between the packing cups, and between the ring s and shaft

. If the fit between the rod packing rings and rod is too loose, more compressed gas will escape

. Periodically replacing the packing rings ensures the correct fit is maintained between packing rings and the rod

.

6.4.2

. 2 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 were calculated by comparing the average rod packing emission swith the averag e emissions from newly installed and worn

in rod packing

. Since the estimate for newly installed rod packing was intended for larger processing and transmission compressors, this analysis uses the estimate to calculate reductions from only gathering6

- 13

and bo osting compressors and not wellhead compressor which are known to be smaller

. The calculation for gathering and boosting reductions is shown in E quation 1

.

Equation 1 where,

= Potential methane emission reductions from gathering and boosting compressors switching from wet seals to dry seals, in million cubic feet per year (MMcf/year) ;

= Number of new gathering and boosting compressors ; E G&B = Methane emission factor for gathering and boosting compressors in Table 6

- 2 , in cubic feet per hour per c ylinder ; E New = Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per hour per cylinder 15 for this analysis ; C = Average number of cylinders for gathering and boosting compressors in Table 6

- 2; O = Percent of time during the calendar year the average gathering and boosting compressor is in the operating and standby pressurized modes, 79.1% ; 8760 = Number of days in a year ; 10 6 = Number of cubic feet in a million cubic feet

. For wellhead reciprocating compressors, this analysis calculates a percentage reduction using the transmission emission factor from the 1996 EPA/GRI report and the minimum emissions rate from a newly i nstalled rod packing to determine methane emission reductions

. The calculation for wellhead compressor reductions is shown in Equation 2 below.

Equation 2
where,

= Potential methane emission reductions from wellhead compressors switching from wet seals to dry seals , in million cubic feet per year (MMcf/year) ;

= Number of new wellhead compressors ; E Well = Methane emission factor for wellhead com pressors from Table 6

- 2 , cubic feet per hour per c ylinder ; C = Average number of cylinders for wellhead compressors in Table 6

- 2; O = Percent of time during the calendar year the average gathering and boosting compressor is in the operating and standby pressurized modes, 100%;6

- 14

E Trans = Methane emissions factor for transmission compressors from Table 6

- 2 in cubic feet per hour per cyli nder ; E New = Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per hour per cylinder 16 for this analysis; 8760 = Number of days in a year ; 10 6 = Number of cubic feet in a million cubic feet

.
Th e emission reductions for the processing, transmission, and storage segments were calculated by multiplying the number of new reciprocating compressors in each segment by the difference between the
average rod packing emission factors in Table 6

- 2 by the a verage emission factor from newly installed rod packing

. This calculation, shown in the E quation 3 below, was performed for each of the natural gas processing, transmission, and storage/LNG sectors.

Equation 3

where,

= Potential methane emission reductions from processing, transmission, or storage compressors switching from wet seals to dry seals, in million cubic feet per year (MMcf/year);

= Number of new processing, transmis sion, or storage compressors; E G&B = Methane emission factor for processing, transmission, or storage compressors in Table 6

- 2, in cubic feet per hour per cylinder; E New = Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per hour per cylinder 17 for this analysis ; C = Average number of cylinders for processing, transmission, or storage compressors in Table 6

- 2; O = Percent of time during the calendar year the average processing, transmission, or storage compressor is in the operating and standby pressurized modes, 89.7%, 79.1% , 67.5% respectively; 8760 = Number of days in a year ; 10 6 = Number of cubic feet in a million cubic feet.
A summary of the potential emission reductions for reciprocating rod packing replacement for e ach of the oil and gas segments is shown in Table 6

- 6. The emissions of VOC and HAP were calculated using the methane emission reductions calculated above the gas composition 18 for each of the segments. Reciprocating compressors in the processing sector wer e assumed to be used to compress production
gas

.6

- 15 Table 6

- 6

. Estimated Annual Reciprocating Compressor Emission Reductions from Replacing Rod Packing

Oil & Gas Segment Number of

New Sources Per Year Individual C ompressor Emission Reductions (t ons/ compressor - y ea r) Nationwide Emission Reductions (t ons/y ea r) Methane VOC HAP Methane VOC HAP
Production (Well Pads) 6,000 0.158 0.0439 0.00165 947 263 9.91

Gathering & Boosting 210 6.84 1.90 0.0717 1,437 400 15.1

Processing 375 18.6 5.18 0.195 3,892 1,082 40.8

Transmission 199 21.7 0.600 0.0178 423 11.7 0.348

Storage 9 21.8 0.604 0.0179 87.3 2.42 0.07186

- 16

6.4.2 .3 Cost Impacts
Costs for the replacement of reciprocating compressor rod packing were obtained from a Natural Gas Star Lessons Learned document 19 which estimated the cost to replace the packing rings to be $1,620 per cylinder. It was assumed that rod packing repla cement would occur during planned shutdowns and maintenance and therefore, no travel costs will be incurred for implementing the rod packing replacement program. In addition, no costs were included for monitoring becausethe rod packing placement is based on number of hours that the compressor operates. The replacement of rod packing for reciprocating compressors occurs on average every four years based on industry information from the Natural Gas STAR Program

. 20 The cost impacts are based on the replacement o f the rod packing 26,000 hours that the reciprocating compressor operates in the pressurized mode

. The number of hours used for the cost impacts was determined using a weighted average of the annual percentage that the reciprocating compressors are pressur ized for all of the new sources

. This weighted hours , on
average, per year the reciprocating compressor is pressurized was calculated to be 98.9 percent

. This percentage was multiplied by the total number of hours in 3 years to obtain a value of 26,000 hou rs

. This calculates to an average of 3 years for production compressors, 3.8 years for gathering and boosting compressors, 3.3 years for processing compressors, 3.8 years for transmission compressors, and 4.4 years for storage compressors using the operati ng factors in Table 6

- 2

. The calculated years were assumed to be the equipment life of the compressor rod packing and were used to calculate the capital recovery factor for each of the segments

. Assuming a n interest rate of 7 percent , the capital recovery factors were calculated to be 0.3848, 0.3122, 0.3490, 0.3122, and 0.2720 for the production, gathering and boosting, processing, transmission, and storage sectors, respectively

. The capital costs were calculated using the average rod packing cost of $1,620 and the average number of cylinders per segment in Table 6

- 2

. The annual costs were calculated using the capital cost and the capital recovery factors

. A summary of the capital and annual costs for each of the oil and gas segments is shown in Table 6

- 7.

M onetary 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. 21 Th is cost was used to calculate theannual cost with gas savings using the methane emiss ion reductions in Table 6

- 6

. The annual cost with savings is shown in Table 6

- 7 for each of the oil and gas segments. The cost effectiveness for the reciprocating rod packing replacement option is presented in Table 6

- 7

. There is no gas savings cost benefi ts for transmission and storage facilities, because they do not own the natural gas that is6

- 17 Table 6

- 7. Cost Effectiveness for Reciprocating Compressor Rod Packing Replacement

Oil and Gas Segment Capital Cost

($2008) Annual Cost per Compressor

($/ compressor - y ea r) VOC Cost Effectiveness ($/t on) Methane Cost Effectiveness ($/t on) Without savings With savings Without savings With savings Without savings With savings

Production $6,480 $2,493 $2,457 $56,847 $56,013 $15,802 $15,570 Gathering & Boosting $5,346 $1,669 $83 $877 $43 $244 $12 Processing $4,050 $1,413

- $2,903 $273

- $561 $76

- $156
Transmission $5,346 $1,669 N/A $2,782 N/A $77 N/A Storage $7,290 $2,276 N/A $3,766 N/A $104 N/A6

- 18

compressed at their compressor stations.

6.4.2 .4 Secondary Impacts
The reciprocating compressor rod packing replacement is an option that prevents the escape of natural gas from the piston rod. No wastes should be created, no wastewater generated, and no electricity maintenan ce and therefore, no travel costs will be incurred for implementing the rod packing replacement program. In addition, no costs were included for monitoring becausethe rod packing

6.4.3 Centrifugal Compressor Dry Seals

6.4.3 .1 Description
Centrifugal compre ssor dry seals operate mechanically under the opposing force created by hydrodynamic grooves and springs

. The hydrodynamic grooves are etched into the surface of the rotating ring affixed to the compressor shaft

. When the compressor is not rotating, the st ationary ring in the seal housing is pressed against the rotating ring by springs

. When the compressor shaft rotates at high speed, compressed gas has only one pathway to leak down the shaft, and that is between the rotating and stationary rings

. This gas is pumped between the rings by grooves in the rotating ring

. The opposing force of high

- pressure gas pumped between the rings and springs trying to push the rings together creates a very thin gap between the rings through which little gas can leak

. While the compressor is operating, the rings are not in contact with each other, and therefore, do not wear or need lubrication

. O

- rings seal the stationary rings in the seal case

. Dry seals substantially reduce methane emissions

. At the same time, they signifi cantly reduce operating costs and enhance compressor efficiency

. Economic and environmental benefits of dry seals include:

 Gas Leak Rates

. During normal operation, dry seals leak at a rate of 6 scfm methane per
compressor

. 22 While this is equivalent to a wet seal’s leakage rate at the seal face, wet seals generate additional emissions during degassing of the circulating oil

. Gas separated from the seal oil before the oil is re

- circulated is usually vented to the atmosphere, bringing the total leakage rate for tandem wet seals to 47.7 scfm methane per compressor

. 23 , 24

 Mechanically Simpler

. Dry seal systems do not require additional oil circulation components and treatment facilities

.6

- 19

 Reduced Power Consumption

. Because dry seals have no accessory oil circulation p umps and systems, they avoid “parasitic” equipment power losses

. Wet seal systems require 50 to 100 kW per hour, while dry seal systems need about 5 kW of power per hour.

 Improved Reliability

. The highest percentage of downtime for a compressor using wet s eals is due to seal system problems

. Dry seals have fewer ancillary components, which translates into higher overall reliability and less compressor downtime.

 Lower Maintenance

. Dry seal systems have lower maintenance costs than wet seals because they do n ot have moving parts associated with oil circulation (e.g., pumps, control valves, relief valves, and the seal oil cost itself).

 Elimination of Oil Leakage from Wet Seals

. Substituting dry seals for wet seals eliminates seal oil leakage into the pipeline, thus avoiding contamination of the gas and degradation of the pipeline.
Centrifugal compressors were found in the processing and transmission sectors based on information in the greenhouse gas inventory

. 25 Therefore, it was assumed that new compressors woul d be located in these sectors only

.
6.4.3 .2 Effectiveness
The control effectiveness of the dry seals was calculated by subtracting the dry seal emissions from a centrifugal compressor equipped with wet seals

. The centrifugal compressor emission factors in Table 6

- 2 were used in combination with an operating factor of 43.6 percent for processing c entrifugal compressors and 24.2 percent for transmission centrifugal compressors

. The operating factor s are used

to acco unt for the percent of time in a year that a compressor is in the operating mode. The operating factors for the processing and transmission sectors are based on data in the EPA/GRI study. 26 The wet seals emission factor is an average of 48 different wet sea l centrifugal compressors

. The dry seal emission factor is based on information from the Natural Gas STAR P rogram. 27 A summary of the emission reduction from the replacement of wet seals with dry seals is shown in Table 6

- 8.

6.4.3 .3 Cost Impacts
The price difference between a brand new dry seal and brand new wet seal centrifugal compressor is insignificant relative to the cost for the entire compressor

. General Electric (GE) stated that a natural gas transmission pipeline centrifu gal compressor with dry seals cost between $50,000 and $100,000 more than the same centrifugal compressor with wet seals

. However, this price difference is only about 1 to 36

- 20

Table 6

- 8

. Estimated Annual Centrifugal Compressor Emission Reductions from Repla cing Wet Seals with Dry Seals

Oil & Gas Segment Number of

New Sources Per Year Individual C ompressor Emission Reductions (ton / compressor - y ea r) Nationwide Emission Reductions (ton /y ea r) Methane VOC HAP Methane VOC HAP Transmission/Storage 16 199 18.0 0.643 3,183 287 10.3

Storage 14 110 3.06 0.0908 1,546 42.8 1.276

- 21

percent of the total cost of the compressor

. The price of a brand new natural gas transmission pipeline centrifugal compressor between 3 , 000 and 5 , 000 horsepower runs between $2 million to $5 million depending on the number of stages, desired pressure ratio, and gas throughput

. The larger the compressor, the less significant the price difference is between dry seals and wet seals. This analysis assumes the additional ca pital cost for a dry seal compressor is $75,000. The annual cost was
calculated as the capital recovery of this capital cost assuming a 10

- year equipment life and 7 percent interest which came to $10,678 per compressor

. The Natural Gas STAR Program estimated that the operation and maintenance savings from the installation of dry seals is $88,300 in comparison to wet
seals

. Monetary savings associated with the amount of gas saved with the replacement of wet seals with dry seals for centrifugal compres sors was estimated using a natural gas price of $4.00 per Mcf. 28 This cost was used to calculate the annual cost with gas savings using the methane emission reductions in Table 6

- 8

. A summary of the capital and annual costs for dry seals is presented in Tab le 6

- 9

. The methane and VOC cost effectiveness for the dry seal option is also shown in Table 6

- 9

. There is no gas savings cost benefits for transmission a nd storage facilities, because it is assumed the owners of the compressor station may not own the nat ural gas that is compressed at the station.

6.4.3 .4 Secondary Impacts
Dry seals for centrifugal compressors are an option that prevents the escape of natural gas across the rotating compressor shaft. No wastes should be created, no wastewater generated, a nd no electricity needed. Therefore, there are no secondary impacts expected due to the installation of dry seals on centrifugal compressors.

6.4.4 Centrifugal Compressor Wet Seals with a Flare

6.4.4 .1 Description
Another control option used to reduce pollutant emissions from centrifugal compressors equipped withwet seals is to route the emissions to a combustion device or capture the emissions and route them to afuel system. A wet seal system uses oil that is circu lated under high pressure between three rings around the compressor shaft, forming a barrier against the compressed gas. The center ring is attached to the rotating shaft, while the two rings on each side are stationary in the seal housing, pressed against a thin film of oil flowing between the rings to both lubricate and act as a leak barrier. Compressed gas becomes absorbed and entrained in the fluid barrier and is removed using a heater, flash tank, or other degassing technique so that the oil can be reci rculated back to the wet seal. The removed gas is either6

- 22 Table 6

- 9

. Cost Effectiveness for Centrifugal Compressor Dry Seals

Oil and Gas Segment Capital Cost ($2008) Annual Cost per Compressor

($/ compressor - yr) VOC Cost Effectiveness ($/t on) Methane Cost Effectiveness ($/t on)

w ithout savings w ith O&M

and gas savings w ithout

savings w ith O&M

and gas savings w ithout

savings w ith O&M and

gas savings

Processing $75,000 $10,678

- $123,730 $595

- $6,892 $ 54

- $6 22

Transmission/Storage $75,000 $10,678

- $77,622 $3,495

- $25,405 $ 9 7

- $7036

- 23

combusted or released to the atmosphere. The control technique investigated in this section is the use of wet seals with the removed gas sent to an enclosed flare.

6.4.4 .2 Effectiveness
Flares have been used in the oil and gas industry to combust gas streams that have VOC and HAP. A flare typically achieves 95 percent reduction of these compounds when operated according to the manufacturer instructions. For this analysis, it was assumed t hat the entrained gas from the seal oil that is removed in the degassing process would be directed to a flare that achieves 95 percent reduction of methane, VOC, and HAP

. The wet seal emissions in Table 6

- 5 were used along with the control efficiency to ca lculate the emissions reductions from this option

. A summary of the emission reductions is presented in Table 6

- 10.

6.4.4 .3 Cost Impacts
The capital and annual cost of the enclosed flare was calculated using the methodology in the EPA Control Cost Manual. 29 The heat content of the gas stream was calculated using information from the gas composition memorandum. 30 A summary of the capital and annual costs for wet seals routed to a flare is presented in Table 6

- 11. The methane and VOC cost effectiveness for the wet seals routed to a flare option is also shown in Table 6

- 12. There is no cost saving estimated for this option because the recovered gas is combusted.

6.4. 4 .4 Secondary Impacts
There are secondary impacts with the option to use wet seals with a flare. T he combustion of the recovered gas creates secondary emissions of hydrocarbons, nitrogen oxide (NO X ), carbon dioxide (CO 2 ), and carbon monoxide (CO) emissions. A summary of the estimated secondary emission are presented in Table 6

- 11. No other wastes shoul d be created or wastewater generated.

6.5 Regulatory Options
The affected facility definition for a reciprocating compressor is defined as a piece of equipment that increases the pressure of a process gas by positive displacement, employing linear movement of the driveshaft . A c entrifugal c ompressor is defined as a piece of equipment that compresses a process gas by means of mechanical rotating vanes or impellers. Therefore these types of compressor would be6

- 24

Table 6

- 10

. Estimated Annual Centrifugal Compressor Emission Reductions from Wet Seals Routed to a Flare

Oil & Gas Segment Number of New Sources Per Year Individual Compressor Emission Reductions (t ons/ compressor - y ea r) Nationwide Emission Reductions (t o ns/y ea r) Methane VOC HAP Methane VOC HAP Processing 16 216 19.5 0.699 3, 283 296 10.6

Transmission/ Storage 14 120 3.32 0.0986 1, 596 4 4.2 1. 316

- 25 Table 6

- 11

. Secondary Impacts from Wet Seals Equipped with a Flare

Industry Segment Secondary Impacts from Wet Seals Equipped with a Flare (tons/year)

Total Hydrocarbons Carbon

Monoxide Carbon

Dioxide Nitrogen

Oxides Particulate

Matter Processing 0.0289 0.0205 7.33 0.00377 Negligible Transmission/Storage 0.00960 0.00889 3.18 0.00163 Negligible6

- 26 Table 6

- 12

. Cost Effectiveness for Centrifugal Compressor Wet Seals Routed to a Flare

Oil and Gas Segment Capital Cost ($2008) Annual Cost per Compressor

($/ compressor - y ea r) VOC Cost Effectiveness ($/t on) Methane Cost Effectiveness ($/t on)
w ithout savings w ith gas

savings w ithout savings w ith gas savings w ithout

savings w ith gas

savings Processing $67,918 $103,371 N/A $5 ,299 N/A $ 478 N/A

Transmission/Storage $67,918 $103,371 N/A $3 1 , 133 N/A $ 862 N/A6

- 27

subject to a New Performance Standard (NSPS) at the time of installation. The following Regulatory options were evaluated:

 Regulatory Option 1: Require replacement of the reciprocating compressor rod packing based

on 26,000 hours of operation while the compressor is pressurized.

 Regulatory Option 2: Require all centrifugal compressors to be equipped with dry seals.

 Regulatory O ption 3: Require centrifugal compressors equipped with a wet seal to route the recovered gas emissions to a combustion device

.

6 .5.1 Evaluation of Regulatory Options
The first regulatory option for replacement of the reciprocating compressor rod packing ba sed on the number of hours that the compressor operates in the pressurized mode was described in Section 6.4.1

. The VOC cost effectiveness from $56,847 for reciprocating compressors located at production pads to $273 for reciprocating compressors located a t processing plants

. The VOC cost effectiveness for the gathering and boosting, transmission, and storage segments were $877, $2,782, and 3,766 respectively

. Based on these cost effectiveness values, Regulatory Option 1 was accepted for the processing, gat hering and boosting, transmission, and storage segments and rejected for the production segment

. The second regulatory option would require all centrifugal compressors to be equipped with dry seals

. As presented in Section 6.4.2, dry seals are effective a t reducing emissions from the rotating shaft of a centrifugal compressor

. Dry seals also reduce operation and maintenance costs in comparison to wet seals

. In addition, a vendor reported in 2003 that 90 percent of new compressors that were sold by the
comp any were equipped with dry seals

. Another vendor confirmed in 2010 that the rate at which new
compressor s ales have dry seals is still 90 percent ; thus, it was as s umed that from 2003 onward, 90 p ercent of new compressors a re equipped with dry seals

. The VO C cost effectiveness of dry seals was calculated to be $595 for centrifugal compressors located at processing plants, and $3,495 for centrifugal compressors located at transmission or storage facilities

. Therefore, Regulatory Option 2 was accepted as a reg ulatory option for centrifugal compressors located at processing, transmission, or storage facilities.
The third regulatory option would allow the use of wet seals if the recovered gas emissions were routed to a flare

. Centrifugal compressors with wet seal s are commonly used in high pressure applications over 3,000 pounds per square inch (psi)

. None of the applications in the oil and gas industry operate at these6

- 28

pressures

. Therefore, it does not appear that any facilities would be required to operate a cen trifugal compressor with wet seals

. The VOC control effectiveness for the processing and transmission/storage segments were $5,299 and $31,133 respectively

. Therefore, Regulatory Option 3 was rejected due to the high VOC cost effectiveness.

6 .5. 2 Nationwid e Impacts of Regulatory Options

Tables 6

- 13 and 6

- 14 summarize the impacts of the selected regulatory options by industry segment

. Regulatory Option 1 is estimated to affect 210 reciprocating compressor s at gathering and boosting stations, 209 reciprocating compressors at processing plants, 20 reciprocating compressors at transmission facilities, and 4 reciprocating compressors at underground storage facilities

. A summary of the capital and annual costs a nd emission reductions for this option is presented in Table 6

- 13

. Regulatory Option 2 is expected to affect 16 centrifugal compressors in the processing segment and 14 centrifugal compressors in the transmission and storage segments. A sum mary of the capital and annual costs and emission reductions for this option is presented in Table 6

- 14.6

- 29 Table 6

- 13

. Nationwide Cost Impacts for R egulatory Option 1

Oil & Gas Segment Number of New Sources Per Year Nationwide Emission Reductions (tons/year) Total Nationwide Costs

VOC Methane HAP Capital Cost ($) Annual Cost

without
s avings ($/yr) Annual Cost

with s avings ($/yr)
Gathering & Boosting 210 400 1,437 15.1 $1,122,660 $ 350,503 $ 17,337

Processing 209 1, 082 3,892 40.8 $ 846,450 $ 295,397

- $ 606,763

Transmission 20 11.7 423 0.348 $1 04,247 $ 32,547 $ 32,547

Storage 4 2.42 87.3 0.0718 $ 29,160 $ 9,104 $ 9,1046

- 30 Table 6

- 14

. Nationwide Cost Impacts for Regulatory Option 2

Oil & Gas Segment Number of New Sources Per Year Nationwide Emission Reductions 1 (tons/year) Total Nationwide Costs a

VOC Methane HAP Capital Cost ($) Annual Cost

w/o Savings ($/y ea r) Annual Cost

w/ Savings ($/y ea r)
Production (Well Pads) 0 0 0 0 0 0 0

Gathering & Boosting 0 0 0 0 0 0 0

Processing 16 1 18 422 4.42 $ 100,196 $ 14 , 266

- $ 120 , 144

Transmission

/Storage 14 3.24 117 0.0962 $ 50 , 098 $ 7,133

- $3 7 , 017

a. The nationwide emission reduction and nationwide costs are based on the emission reductions and costs for 2 centrifugal compressors with wet seals located a processing facility and 1 centrifugal compressor equipped with wet seal located at a transmission or storage facility.6

- 31

6 .6 References

1 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.

2 Memorandum to Bruce Moore, U.S. Environmental Protection Agency from Heather Brown, EC/R . Gas Composition Methodology. July 2011.

3 EPA/GRI (1996) Methane Emission from the Natural Gas Industry.Vol. 11.Pages 11

– 15. Available at: http://epa.gov/gasstar/documents/emissions_report/11_compressor.pdf

4 Memorandum to Bruce Moore, U.S. Environment al Protection Agency from Heather Brown, EC/R. Gas Composition Methodology. July 2011.

5 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks1990

- 2008. Was hington, DC. 2010.

6 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks1990

- 2009. Washington, DC. April 2011.

7 EPA (2010), Mandatory Reporting of Greenh ouse Gases from Petroleum and Natural Gas Systems

– Subpart W, <http://edocket.access.gpo.gov/2010/pdf/2010

- 28655.pdf>

8 El Paso (2010), Comments from El Paso Corporation on the Proposed Rule for Mandatory Reporting of Greenhouse Gases: Petroleum and Natur al Gas Systems. Federal Register, Vol. 75, No. 69, Docket ID No.EPA

- HQ

- OAR

- 2009

- 0923.

9 HPDI LLC (2008), U.S. Production.<http://hpdi.com>

10 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenh ouse Gas Inventory: Emission and Sinks1990

- 2008. Washington, DC. 2010.

11 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks1990

- 2009. Washington, DC. Apr il 2011.

12 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks1990

- 2008. Washington, DC. 2010.6

- 3 2

13 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks1990

- 2009. Washington, DC. April 2011.

14 EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR. Envi ronmental Protection Agency.

15 EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR. Environmental Protection Agency.

16 EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod Packi ng Systems. Natural Gas STAR. Environmental Protection Agency.

17 EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR. Environmental Protection Agency.

18 Memorandum to Bruce Moore, U.S. Environmental Protection Agency from Heather Brown, EC/R. Gas Composition Methodology. July 2011.

19 EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR. Environmental Protection Agency.

20 EPA (2006). Lessons Learne d: Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR. Environmental Protection Agency.

21 U.S. Energy Information Administration.Annual U.S. Natural Gas Wellhead Price.Energy Information Administration Natural Gas Navigator. R etrieved online on December 12, 2010 at <http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm>

22 EPA (2006), Lessons Learned Document. “Replacing Wet Seals with Dry Seals in Centrifugal Compressors.” October 2006. http://epa.gov/gasstar/documents/ll_wetseals.pdf

23 “Methane’s Role in Promoting Sustainable Development in the Oil and Natural Gas Industry”. US EPA, ICF International, PEMEX, EnCana Oil & Gas, Hy

- Bon Engineering, Pluspetrol, Gazprom, VNIIGAZ. World Gas Co nference 10/2009. Available at: http://www.epa.gov/gasstar/documents/best_paper_award.pdf

24 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2 Emissions from Pe troleum Systems. Greenhouse Gas Inventory: Emission and Sinks1990

- 2009. Washington, DC. April 2011. Annex 3. Page A

153. http://epa.gov/climatechange/emission s/downloads11/US

- GHG

- Inventory

- 2011

- Annex

- 3.pdf

25 U.S Environmental Protection Agency.Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks1990

- 2008. Washington, DC. 2010.6

- 33

26 National Risk Mana gement 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.

27 EPA (200 6). Lessons Learned: Replacing Wet Seals with Dry Seals in Centrifugal Compressors. Natural Gas STAR. Environmental Protection Agency.

28 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>

29 EPA Air Pollution Control Cost Manual

- Sixth Edition, (EPA 452/B

- 02

- 001)

30 Memorandum to Bruce Moore, U.S. Environmental Protection Agency from Heather Brown, EC/R. Gas Composition Methodology. July 2011.7

- 1 7.0 STORAGE VESSELS
Storage vessels , or storage tanks, are sources of air emissions in the oil and natural gas sector. This chapter provides a description of the types of storage vessels present in the oil and gas sector, and provides emission estimates for a typical storage vessel as well as nationwide emiss ion estimates. Control techniques employed to reduce emissions from storage vessels are presented, along with costs, emission reductions, and secondary impacts. Finally, this chapter provides a discussion of considerations used in developing regulatory alt ernatives for storage vessels.

7.1 Process Description
Storage vessels in the oil and natural gas sector are used to hold a variety of liquids, including crude oil, condensates, produced water, etc. Underground crude oil contains many lighter hydrocarbons in

s olution. When the oil is brought to the surface and processed, many of the dissolved lighter hydrocarbons (as well as water) are removed through as series of high

- pressure and low

- pressure separators. Crude oil under high pressure conditions is passed thro ugh either a two phase separator (where the associated gas is removed and any oil and water remain together) or a three phase separator (where the associated gas is removed and the oil and water are also separated). At the separator, low pressure gas is ph ysically 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 shipped off

- site. The remaining hydrocarbons in the oil are released from the oil as vapo rs 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 remaining hydrocarbons from storage vessels are a function of working, breathin g (or standing), and flash losses. Working losses occur when vapors are displaced due to the emptying and filling of storage vesse l s . Breathing losses are the release of gas associated with daily temperature fluctuations and other equilibrium effects. Flas h losses occur when a liquid with entrained gases is transferred from a vessel with higher pressure to a vessel with lower pressure, thus allowing entrained gases or a portion of the liquid to vaporize or flash. In the oil and natural gas production segmen t, flashing losses occur when live crude oils or condensates flow into a storage vessel from a processing vessel operated at a higher pressure. Typically, the larger the pressure drop, the more flash emission s will occur in the storage stage. Temperature of the liquid may also influence the amount of flash emissions.7

- 2

The volume of gas vapor emitted from a storage vessel depends on many factors. Lighter crude oils flash more hydrocarbons than heavier crude oils. In storage vessels where the oil is frequently cycled and the overall throughput is high, working losses are higher. Additionally, the operating temperature and pressure of oil in the separator dumping into the storage vessel will affect the volume of flashed gases coming out of the oil.
The composition of the vapors from storage vessels varies, and the largest component is methane , but also includes ethane, butane, propane, and hazardous air pollutants (HAP) such as benzene, toluene, ethylbenzene, xylene (collectively referred to as BTEX), and n

- hexane.

7.2 E missions Data

7.2.1 Summary of Major Studies and Emissions
Given the potentially significant emissions from storage vessels, there have been numerous studies conducted to estimate these emissions. Many of these studies were consulted to evaluate the emissions and emission reduction options for emissions from storage vessels. Table 7

- 1 presents a summary of these studies, along with an indication of the type of information available in each study.

7.2.2 Representative Storage Vessel Emissions
Due to the variability in the sizes and throughputs, model tank batteries were developed to represent the ranges of sizes and population distribution of storage vessels located at tank batteries throughout the sector. Model tank batteries were not intended to represent any single f acility, but rather a range of facilities with similar characteristics that may be impacted by standards. Model tank batteries were developed for condensate tank batteries and crude oil tank batteries . Average VOC emissions were then developed and applied to the model tank batteries.

7.2.2.1 Model Condensate Tank Batteries
During the development of the national emissions standards for HAP (NESHAP) for oil and natural gas production facilities (40 CFR part 63, s ubpart HH), model plants were developed to represent condensate tank batteries across the industry. 1 For this current analysis, the most recent inventory data available was the 2008 U.S. Greenhouse Gas Emissions Inventory. 2 , 3 Therefore, 2008 was chosen to

r epresent the base year for this impacts analysis. To estimate the current condensate battery population and distribution across the model plants, the number of tanks represented by the model plants was scaled7

- 3 Table 7

- 1

. Major Studies Reviewed for Consideration of Emissions and Activity Data

Report Name Affiliation Year of Report Activity

Factors Emission

Figures Control

Information VOC Emissions from Oil and Condensate Storage Tanks 4 Texas Environmental Research Consortium 2009 Regional X X Lessons Learned from Natural Gas STAR Partners:Installing Vapor Recovery Units on Crude Oil Storage Tanks 5 EPA 2003 National X
Upstream Oil and Gas Storage Tank Project Flash Emissions Models Evaluation

– Final Report 6 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 2008 n/a X

E&P TANKS 8 American Petroleum Institute National X Inventory of U.S. Greenhouse Gas Emissions and Sinks 2 , 3 EPA 2008 and 2009 National X7

- 4

from 1992 (the year for which that the model plants were developed under the NESHAP) to 2008 for this analysis. Based on this approach, it was estimated that there were a total of 59,286 existing condensate tanks in 2008. Condensate throughput data from the U.S. Greenhouse Gas Emissions Inventory was used to scale up from 1992 the condensate tank populations for eac h model condensate tank battery under the assumption that an increase in condensate production would be accompanied by a proportional increase in number of condensate tanks. The inventory data indicate that condensate production increased from a level of 1 06 million barrels per year (MMbbl/yr) in 1992 to 124 MMbbl/yr in 2008. This increase in condensate production was then distributed across the model condensate tank batteriesin the same proportion as was done for the NESHAP. T he model condensate tank batteri es are presented in Table 7

- 2.

7.2.2.2 Model Crude Oil Tank Batteries
According to the Natural Gas STAR program, 5 there were 573,000 crude oil storage tanks in 2003

. According to the U.S. Greenhouse Gas Emissions Inventory, crude oil production decreased from 1,464 MMbbl/yr in 2003 to 1,326 MMbbl/yr (a de crease of approximately 9.4 percent) in 2008 . Therefore, it was assumed that the number of crude oil tanks in 2008 were approximately 90.6 percent of the number of tanks identified in 2003 . Therefore, for this analysis it was assumed that there were 519,16 1 crude oil storage tanks in 2008. During the development of the NESHAP, model crude oil tank batteries were not developed and a crude oil tank population was not estimated. Therefore, it was assumed that the percentage distribution of crude oil storage ta nks across the four model crude oil tank batter y classifications was the same as for condensate tank batteries.Table 7

- 3 presents the model crude oil tank batteries.

7.2.2.3 VOC Emissions from Condensate and Crude Oil Storage Vessels

Once t he modelcondensate and crude oil tank battery distribution swere developed, VOC emissions from a representative storage vessel were estimated. Emissions from storage vessels vary considerably depending on many factors, including , but not limited to , through put, API gravity, Reid vapor pressure, separator pressure, etc. The American Petroleum Institute (API) has developed a software program called E&P TANKS which contains a dataset of more than 100 storage vessels from across the country. 8 A summary of the information contained in the dataset, as well as the output from the E&P TANKS program, is presented in Appendix A of this document. According to in dustry representatives, this7

- 5 Table 7

- 2. Model Condensate Tank Batteries
Model Condensate Tank Battery Parameter E F G H Condensate throughput (bbl/day) a 15 100 1,000 5,000 Condensate throughput (bbl/yr) a 5,475 36,500 365,000 1,825,000 Number of fixed

- roof product storage vessels a 210 barrel capacity 4 2 500 barrel capacity 2 2 1,000 barrel capacity 2 4 Estimated tank battery population (1992) a 12,000 500 100 70 Estimated tank battery population (2008) b 14,038 585 117 82 Total number of storage vessels (2008) b 56,151 2,340 468 328 Percent of number of storage vessels in model condensate tank battery 94.7% 3.95% 0.789% 0.552%
Percent of throughput per model condensate tank battery a 26% 7% 15% 51% Total tank battery condensate throughput (MMbbl/yr) c 32.8 9.11 18.2 63.8 Condensate throughput per model condensate battery (bbl/day) 6.41 42.7 427 2,135
Condensate throughput per storage vessel (bbl/day) 1.60 10.7 106.8 534 Minor discrepancies may be due to rounding.

a. Developed for NESHAP (Reference 1 ). b. Population of tank batteries for 2008 determined based on condensate throughput increase from 106 MMbbl/yr in 1992 to 124 MMbbl/yr in 2008 (References 2 , 3 ).

c. 2008 condensate production rate of 124 MMbbl/yr distributed across model tank batteries using same relative ratio as developed for NESHAP (Reference 1 ).7

- 6 Table 7

- 3. Model Crude Oil Tank Batteries
Model Crude Oil Tank Battery Parameter E F G H Percent of number of condensate storage vessels in model size range a 94.7% 3.95% 0.789% 0.552% Number of storage vessels b 491,707 20,488 4,098 2,868 Percent of throughput across condensate tank batteries 26% 7% 15% 51% Crude oil throughput per model plant category (MMbbl/yr) 351 97.5 195 683 Crude oil throughput per storage vessel (bbl/day) 1.96 13.0 130 652 Minor discrepancies may be due to rounding.

a. Same relative percent of storage vessel population developed for model condensate tank batteries.Refer to Table 7

- 2. b. Calculated by applying the percent of number of condensate storage vessels in model size range to total number of crude oil storage vessel s (519,161 crude oil storage vessels estimated for 2008) (Reference 5 ).

c. Same relative percent of throughput developed for model condensate tank batteries.Refer to Table 7

- 2.7

- 7

dataset in combination with the output of the E&P TANKS program is representative of the various VOC emissions from storage vessels across the country. 9

The more than 100 storage vessels provided with the E&P TANKS progr am, which had varying characteristics, were modeled with a constant throughput ( based on the assumption that emissions would increase in proportion with throughput) and the relationship of these different characteristics and emissions was studied . While man y of the characteristics impacted emissions, a correlation was found to exist between API gravity and emissions. The average API gravity for all storage vessels in the data set was approximately 40 degrees. Therefore, we selected an API gravity of 40 degre es as a parameter to distinguish between lower emitting storage vessel s and higher emitting storage vessels

. i While the liquid type was not specified for the storage vessels modeled in the study, it was assumed that condensate storage vessels would have higher emissions than crude oil storage vessels . Therefore, based on this study using the E&P TANKS program, it was assumed for this analysis that liquids with API gravity equal to or greater than 40 degrees should be classified as condensate and liquids with API gravity less than 40 degrees should be classified as crude oil.

The VOC emissions from all storage vessels in the analysis are presented in Appendix A. Table 7

- 4 presents a summary of the average VOC emissions from all storage vessels as well as th e average VOC emissions from the storage vessels identified as being condensate storage vessels and those identified as being crude oil storage vessels . As shown in Table 7

- 4, the storage vessels were modeled at a constant throughput of 500 bpd

. ii A n average emission factor was developed for each type of liquid. The average of condens ate storage vessel VOC emissions was modeled to be 1,046 tons/year or 11.5 lb VOC/bbl and the average of crude oil storage vessel VOC emissions was modeled to be 107 tons/year or 1.18 lb VOC/bbl. These emission factors were then applied to each of the two sets of model storage vessels in Tables 7

- 2 and 7

- 4 to develop the VOC emissions from the model tank batteries. These are presented in Table 7

- 5.

i The range of VOC emissions within the 95 percent confidence interval for storage vessels with an API gravity greater than 40 degrees was from 667 tons/year to 1425 tons/year . The range for API gravity less than 40 degrees was 76 tons/year to 138. ii This throughput was originally chosen for this analysis to be equal to the 500 bbl/day throughput cutoff in subpart HH. While not part of the analysis described in this document, one of the original objectives of the E&P TANKS analysis was to assess the level of emissions associated with a storage vessel with a throughput below this cutoff. Due to the assumption tha t emissions increase and decrease in proportion with throughput, it was decided that using a constant throughput of 500 bbl/ day would still provide the information necessary to determine VOC emissions from model condensate and crude oil storage vessels for this document.7

- 8 Table 7

- 4

. Summary of Data from E&P TANKS Modeling

Parameter a Average of Dataset Average of

Storage Vessels with API Gravity > 40 degrees Average of

Storage Vessels with API Gravity
< 40 degrees Throughput Rate (bbl) 500 500 500 API Gravity 40.6 52.8 30.6 VOC Emissions ( tons/year ) 531 1046 107

Emission factor (lb/bbl) 5.8 11.5 1.18
a. Information from analysis of E&P Tanks dataset, refer to Appendix A.7

- 9 Table 7

- 5. Model Storage Vessel VOC Emissions

Parameter Model Tank Battery E F G H Model Condensate Tank Batteries Condensate throughput per storage vessel (bbl/day) 1.60 10.7 107 534 VOC Emissions ( tons/year ) b 3.35 22.3 223 1117 Model Crude Oil Tank Batteries Crude Oil throughput per storage vessel (bbl/day) c 2.0 13 130 652 VOC Emissions ( tons/year ) d 0.4 2.80 28 140
a. Condensate throughput per storage vessel from table 7

- 2. b. Calculated using the VOC emission factor for condensate storage vessels of 11.5 lb VOC/bbl condensate.

c. Crude oil throughput per storage vessel from table 7

- 3. d. Calculated using the VOC emission factor for crude oil storage vessels of 1.18 lb VOC/bbl crude oil.7

- 10

7.3 Nationwide Baseline Emissions from New or Modified Sources

7.3.1 Overview of Approach
The first step in this analysis is to estimate nationwide emissions in absence of a federal rulemaking, referred to as the nationwide baseline emissions estimate. In order to develop the baseline emissions estimate, the number of new storage vessels expect ed in a typical year was calculated and then multiplied by the expected uncontrolled emissions per storage vessels presented in Table 7

- 5. In addition, to ensure no emission reduction credit was attributed to new sources that would already be required to b e controlled under State regulations, it was necessary to account for the number of storage vessels already subject to State regulations as detailed below.

7.3.2 Number of New Storage Vessels Expected to be Constructed or Reconstructed
The number of new storage vessels expected to be constructed was determined for the year 2015 (the year of analysis for the regulatory impacts)

. To do this, it was assumed that the number of new or modified storage vessels would increase in proportion wit h increases in production. The Energy Information Administration (EIA), published crude oil production rates up to the year 2011. 10 Therefore, using the f

orecast function in Microsoft Excel ® , crude oil production was predicted for the year 2015. iii From 2009 to 2015, iv the expected grow th of crude oil production was projected to be 8.25 percent (from 5.36 bpd to 5.80 bpd). Applying this expected growth to the number of existing storage vessels results in an estimate of 4,890 new or modified condensate storage vessels and 42,811 new or modified crude oil storage vessels

. The number of new or modified condensate and crude oil storage vessels expected to be constructed or reconstructed is presented in Table 7

- 6.

7.3.3 Level of Controlled Sources in Absence of Federal Regulation
As stated previous ly, to determine the impact of a regulation, it was first necessary to determine the current level of emissions from the sources being evaluated, or baseline emissions. T o more accurately estimate baseline emissio ns for this analysis, and to ensure no emission reduction credit was attributed

iii The crude oil production values published by the EIA include leased condensate. Therefore, the increase in crude oil production was assumed to be valid for both crude oil and condensate tanks for the purpose of this analysis. iv For the purposes of estimating growth, the crude oil production rate in the year 2008 was considered an outlier for production and the refore was not used in this analysis.7

- 11 Table 7

- 6. Nationwide Baseline Emissions for Storage Vessels

Model Tank Battery E F G H Total Model Condensate Tank Batteries Total number of storage vessels (2008) 56,151 2,340 468 328 59,286 Total projected number of new or modified storage vessels (2015) a 4,630 193 39 27 4,889 Number of uncontrolled storage vessels in absence of federal regulation b 1,688 70 14 10 1,782 Uncontrolled VOC Emissions from storage vessel at model tank battery c 3.35 22.3 223 1,117 1,366
Total Nationwide Uncontrolled VOC Emissions 5,657 1,572 3,143 11,001 21,373 Model Crude Oil Tank Batteries Total number of storage vessels (2008) 491,707 20,488 4,098 2,868 519,161 Total projected number of new or modified storage vessels (2015) a 40,548 1,689 338 237 42,812 Number of uncontrolled storage vessels in absence of federal regulation b 14,782 616 123 86 15,607 Uncontrolled VOC Emissions from storage vessel at model tank battery c 0.4 2.80 28 140 171
Total Nationwide Uncontrolled VOC Emissions 6,200 1,722 3,444 12,055 23,421 Minor discrepancies may be due to rounding
a. Calculated by applying the expected 8.25 percent industry growth to the number of storage vessels in 2008. b. Calculated by applying the estimated 36 percent of storage vessels that are uncontrolled in the absence of a Federal Regulation to the total projected number of new or modified storage vessels in 2015.
c. VOC Emissions from individual storage ves sel at model tank battery, see Table 7

- 5.7

- 12

for sources already being controlled, it was necessary to determine which storage vessels were already being controlled. To do this, the 2005 National Emissions Inventory (NEI) was used.Storage vessels in the oil a nd natural gas sector were identified under the review of the maximum achievable control technology (MACT) standards. 11 There were 5,412 storage vessels identified in the NEI, and of these, 1,973 (or 36 percent) were identified as being uncontrolled. Therefore, this percent of storage vessels that would not require controls under State regulations was applied to the number of new or modified storage vessel s results in an estimate of 1,782 new or modified condensate storage vessels and 15,607 new or modified crude oil storage vessels .These are also presented in Table 7

- 6.

7.3.4 Nationwide Emission Estimates for New or Modified Storage Vessels

Nationwide emissions estimates are presented in Table 7

- 6 for condensate storage vessels and crude oil storage vessels . Model storage vessel emissions were multiplied by the number of expected new or modified storage vessels that would be uncontrolled in the absence of a feder al regulation.As shown in Table 7

- 6, the baseline nationwide emissions are estimated to be 21,373 tons/year for condensate storage vessels and 23,421 tons/year for crude oil storage vessels

.

7.4 Control Techniques

7.4.1 Potential Control Techniques
In analyzing controls for storage vessels, we reviewed control techniques identified in the Natural Gas STAR program and state regulations. We identified two ways of controlling storage vessel emissions, both of which can reduce VOC emissions by 95 percent . One option would be to install a vapor recovery unit (VRU) and recover all the vapors from the storage vessel s . The other option would be to route the emissions from the storage vessel s to a combustor

. These control technologies are described below along with their effectiveness as they apply to storage vessels in the oil and gas sector, cost impacts associated with the installation and operation of these control technologies, and any secondary impacts associated with their use.

7.4.2 Vapor Recovery Units

7.4.2.1 Descr iption
Typically, with a VRU, hydrocarbon vapors are drawn out of the storage vessel under low pressure and are piped to a separator, or suction scrubber, to collect any condensed liquids , which are typically7

- 13

recycled back to the storage vessel . Vapors from the separator flow through a compressor that provides the low

- pressure suction for the VRU system. Vapors are then either sent to the pipeline for sale or used

as on

- site fuel. 5

7.4.2.2 Effectiveness
Vapor recovery units have been shown to reduce VOC emissions from storage vessels by approximately 95 percent. Error! Bookmark not defined. 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 gather ing line is available to convey the recovered salable gas product to market or to further processing. A VRU also does not have secondary air impacts, as described below. However, a VRU cannot be used in all instances. Some conditions that affect the feasib ility of VRU are: availability of electrical service sufficient to power the
compressor; fluctuations in vapor loading caused by surges in throughput and flash emissions from the storage vessel ; potential for drawing air into condensate storage vessel s cau sing an explosion hazard; and lack of appropriate destination or use for the vapor recovered.

7.4.2.3 Cost Impacts
Cost data for a VRU was obtained from an Initial Economic Impact Analysis (EIA) prepared for proposed state

- only revisions to a Colorado regulation. C ost information contained in the EIA was assumed to be giving in 2007 dollars. 7 Therefore costs were escalated to 2008 dollars using the CE Indices for 2007 (525.4) and 2008 (575.4). 12 According to the EIA, the purchased equipment cost of a VRU was estimated to be $85,423 (escalated to 2008 dollars from $75,000 in 2007 dollars). Total capital investment, including freight and design and installation was estimated to be $98,186. These co st data are presented in Table 7

- 7. Total annual costs were estimated to be $18,983/year.

7.4.2.4 Secondary Impacts

A VRU is a pollution prevention technique that is used to recover natural gas that would otherwise be emitted

. No secondary emissions (e.g., nitroge n oxides, particulate matter, etc.) would be generated, no wastes should be created, no wastewater generated, and no electricity needed

. Therefore, there are no secondary imp acts expected due to the use of a VRU

.7

- 14

Table 7

- 7. Total Capital Investment and Total Annual Cost of a Vapor Recovery Unit

Cost Item a Capital

Costs ($) Non

Recurring, One

- time Costs ($) Total

Capital Investment ($) b O&M

Costs ($) Savings

due to Fuel Sales ($/yr) Annualized

Total Cost ($/yr) c
VRU $78,000 Freight and Design $1,500 VRU Installation $10,154 Maintenance $8,553 Recovered natural gas ($1,063) Subtotal Costs (2007) $78,000 $11,654 $8,553 ($1,063) Subtotal Costs (2008) d $85,423 $12,763 $98,186 $9,367 ($1,164)

Annualized costs (using 7% interest, 15 year equipment life) $9,379 $1,401 n/a n/a $18,983

Minor discrepancies may be due to rounding
a. Assume cost data provided is for the year 2007. Reference 7

. b. Total Capital Investment is the sum of the subtotal costs for capital costs and nonrecurring one

time costs.
c. Total Annual Costs is the sum of the annualized capital and recurring costs, O&M costs, and savings due to fuel sales. d. Costs are escalated to 2008 dollars using the CE Indices for 2007 (525.4) and 2008 (575.4)

. Reference 12

.7

- 15

7.4.3 Combustors

7.4.3.1 Description and Effectiveness

Combustors are also used to control emissions from condensate and crude oil storage vessels

. The type of combustor used is a high

- temperature oxidation process used to burn combustible components, mostly hydroc arbons, found in waste streams. 13 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. 14 For this analysis, t he types of comb ustors installed for the oil and gas sector are assumed to achieve 95 percent efficiency. 7 Combustors do not have the same operational issues as VRUs, however secondary impacts are associated with combustors as discussed below.

7.4.3.2 Cost Impacts

Cost data for a combustor was also obtain ed from the Initial EIA prepared for proposed state

- only revisions to the Colorado regulation. 7 As performed for the VRU, costs were escalated to 2008 dollars using the CE Indices for 2007 (525.4) and 2008 (575.4). 12 According to the EIA, the purchased equipment cost of a combustor , includin g an auto igniter and surveillance system was estimated to be $ 23,699 (escalated to 2008 dollars from $ 21,640 in 2007 dollars). Total capital investment, including freight and design and installation was estimated to be $ 32,301 . These cost data are present ed in Table
7

- 8 . Total annual costs were estimated to be $ 8,909 /year.

7.4.3.3 Secondary Impacts
Combustion and partial combustion of many pollutants also create secondary pollutants including nitrogen oxides, carbon monoxide, sulfur oxides, carbon dioxide, and smoke/particulates. R eliable data for emission factors from combustors on condensate and crude oil storage vessel s are limited. Guidelines published in AP

- 42 for flare operations are based on tests from a mixture containing 80 percent propylene and 20 percent propane. 13 These emissions factors, however, are the best indication for secondary pollutants from combustors currently ava ilable. The secondary emission sper storage vessel are provided in Table 7

- 9.7

- 16

Table 7

- 8. Total Capital Investment and Total Annual Cost of a Combustor

Cost Item a Capital Costs ($) Non

Recurring, One

- time Costs ($) Total

Capital Investment ($) b O&M

Costs ($) Annualized

Total Cost ($/yr) c
Combustor $16,540 Freight and Design $1,500 Combustor Installation $6,354 Auto Igniter $1,500 Surveillance System d $3,600 Pilot Fuel $1,897 Maintenance $2,000 Data Management $1,000 Subtotal Costs (2007) $21,640 $7,854 $4,897 Subtotal Costs (2008) e $23,699 $8,601 $32,301 $5,363 Annualized costs (using 7% interest, 15 year equipment life) $2,602 $944 n/a $8,909

Minor discrepancies may be due to rounding
a. Assume cost data provided is for the year 2007. Reference 7

. b. Total Capital Investment is the sum of the subtotal costs for capital costs and nonrecurring one

time costs.
c. Total Annual Costs is the sum of the annualized capital and recurring costs, O&M costs, and savings due to fuel sales. d. Surveillance system identifies when pilot is not lit and attempt to relight it, documents the duration of time when the pilot is n ot lit, and notifies and operator that repairs are necessary.
e. Costs are escalated to 2008 dollars using the CE Indices for 2007 (525.4) and 2008 (575.4)

. Reference 12

.7

- 17

Table 7

- 9. Secondary Impacts for Combustors used to Control Condensate and Crude Oil Storage Vessels

Pollutant Emission

Factor Units Emissions per Storage Vessel ( tons/year ) a THC 0.14 lb/MMBtu 0.0061 CO 0.37 lb/MMBtu 0.0160 CO 2 60 Kg/MMBtu b 5.62 NO X 0.068 lb/MMBtu 2.95E

- 03 PM 40 μg/l (used lightly smoking flares due to criteria that flares should not have visible emissions i.e. should not smoke) 5.51E

- 05

a. Converted using average saturated gross heating value of the storage vessel vapor (1 , 968 Btu/scf) and an average vapor flow rate of 44.07 Mcf per storage vessel . See Appendix A. b. CO 2 emission factor obtained from 40 CFR Part 98, subpart Y, Equation Y

- 2.7

- 18

7.5 Regulatory Options and Nationwide Impacts of Regulatory Option s

7.5.1 Consideration of Regulatory Options for Condensate and Crude Oil Storage Vessels

The VOC emissions from storage vessels vary significantly, depending on the rate of liquid entering and passing through the vessel (i.e., its throughput), the pressure of th e liquid as it enters the atmospheric pressure storage vessel, the liquid’s volatility and temperature of the liquid.Some storage vessels have negligible emissions, such as those with very little throughput and/or handling heavy liquids entering at atmosph eric pressure . Therefore, in order to determine the most cost effective means of control ling the storage vessels , a cutoff was evaluated to limit the applicability of the standards to these storage vessels

. Rather than require a cutoff in terms of emission s that would require a facility to conduct an emissions test on their storage vessel , a throughput cutoff was evaluated. It was assumed that facilities would have storage vessel throughput data readily available. Therefore, we evaluated the costs of contro lling storage vessels with varying throughputs to determine which throughput level would provide the most cost effective control option.
The standard would require an emission reduction of 95 percent, which, as discussed above, could be achieved with a VRU or a combustor . A combustor is an option for tank batteries because of the operational issues associated with a VRU as discussed above.However the use of a VRU is preferable to

a combustor because a combustor destroys, rather than recycle s , valuable resource s and there are secondary impacts associated with the use of a combustor . Therefore, the cost impacts associated a VRU installed for the control of storage vessels were evaluated.
To conduct this evaluation, emission factor data from a study prepared for the Texas Environmental Research Consortium 15 was used to represent emissions from the different throughputs being evaluated. For condensate storage vessels , an emission factor of 33.3 lb VOC/bbl was used and for crude oil storage vessels , an emission facto r of 1.6 lb VOC/bbl was used. Using the throughput for each control option, an equivalent emissions limit was determined. Table 7

- 10 presents the following regulatory options considered for condensate storage vessels :

 Regulatory Option 1: Control condensate storage vessels with a throughput greater than 0.5 bbl/day (equivalent emissions of 3.0 tons/year );7

- 19

Table 7

- 10. Options for Throughput Cutoffs for Condensate Storage Vessels

Regulatory Option Throughput

Cutoff (bbl/day) Equivalent

Emissions Cutoff ( tons/year )

a Emission Reduction ( tons/year ) b Annual Costs for VRU ($/yr) c Cost

Effectiveness ($/ton) Number

of impacted units d 1 0.5 3.0 2.89 $18,983 $6,576 1782 2 1 6.1 5.77 $18,983 $3,288 94 3 2 12.2 11.55 $18,983 $1,644 94 4 5 30.4 28.87 $18,983 $658 24 Minor discrepancies may be due to rounding

a. Emissions calculated using emission factor of 33.3 lb VOC/bbl condensate and the throughput associated with each option. b. Calculated using 95 percent reduction
c. Refer to Table 7

- 7 for VRU Annual Costs. d. Number of impacted units determined by evaluating which of the model tank batteries and storage vessel populations associated with each model tank battery (refer to Table 7

- 6) would be subject to each regulatory opti on. A storage vessel at a model tank battery was considered to be impacted by the regulatory option if its throughput and emissions were greater than the cutoffs for the option.7

- 20

 Regulatory Option 2: Control condensate storage vessels with a throughput greater than 1 bbl/day (equivalent emissions of 6 tons/year );

 Regulatory Option 3: Control condensate storage vessels with a throughput greater than 2 bbl/day (equivalent emissions of 12 tons/year );

 Regulatory Option 1: Control condensate storage vessels with a throughput greater than 5.0 bbl/day (equivalent emissions of 30 tons/year );

As shown in Table 7

- 10, Regulatory Option 1 is not cost effective for condensate storage vessels with a throughput of 0.5 bbl/day.Therefore Regulatory Optio n 1 is rejected.Since the cost effectiveness associated with Regulatory Option 2 is acceptable ($3,288/ton), this option was selected. As shown in
Table 7

- 5, Model Condensate Storage Vessel Categories F, G, and H have throughputs greater than 1 bbl/day and emissions greater than 6 tons/year . Therefore, for the purposes of determining impacts, the populations of new and modified condensate storage vessels associated with categories F, G, and H are assumed to be required to reduce their emissions by 95 percen t, a total of 94 new or modified condensate storage vessels

. A similar evaluation was performed for crude oil vessels and is presented in Table 7

- 11 for the following regulatory options:

 Regulatory Option 1: Control crude oil storage vessel s with a through put greater than 1 bbl/day (equivalent emissions of 0.3 tons/year );

 Regulatory Option 2: Control condensate storage vessel s with a throughput greater than 5 bbl/day (equivalent emissions of 1.5 tons/year );

 Regulatory Option 3: Control condensate storage ve ssel s with a throughput greater than 20 bbl/day (equivalent emissions of 6 tons/year );

 Regulatory Option 1: Control condensate storage vessel s with a throughput greater than 50 bbl/day (equivalent emissions of 15 tons/year );

As show n in Table 7

- 11, Regulatory Options 1 and 2 are not cost effective crude oil storage vessel s with a throughput of 1 and 5 bbl/day, respectively. Therefore Regulatory Options 1 and 2 are rejected.Since the cost effectiveness associated with Regulatory Optio n 3 is acceptable ($3, 422 /ton), this option was selected. As shown in Table 7

- 5, Model Crude Oil Storage Vessel CategoriesG and H have throughputs greater than 20 bbl/day and emissions greater than 6 tons/year . Therefore, for the purposes of determining im pacts, the populations of new and modified crude oil storage vessels associated with categories G7

- 21

Table 7

- 11. Options for Throughput Cutoffs for Crude Oil Storage Vessels

Regulatory Option Throughput

Cutoff (bbl/day) Equivalent

Emissions Cutoff ( tons/year )

a Emission Reduction ( tons/year ) b Annual Costs for VRU ($/yr) c Cost

Effectiveness ($/ton) Number

of impacted units d 1 1 0.3 0.28 $18,983 $68,432 15607 2 5 1.5 1.4 $18,983 $13,686 825 3 20 5.8 5.55 $18,983 $3,422 209 4 50 14.6 13.87 $18,983 $1,369 209 Minor discrepancies may be due to rounding
a. Emissions calculated using emission factor of 1.6 lb VOC/bbl condensate and the throughput associated with each option. b. Calculated using 95 percent reduction
c. Refer to Table 7

- 7 for VRU Annual Costs. d. Number of impacted units determined by evaluating which of the model tank batteries and storage vessel populations associated with each model tank battery (refer to Table 7

- 6) would be subject to each regulatory option. A storage vessel at a model tank battery was considered to be impacted by the regulatory option if its throughput and emissions were great er than the cutoffs for the option.7

- 22

and H are assumed to be required to reduce their emissions by 95 percent, a total of 209 new or modified condensate storage vessels

.

7.5.2 Nationwide Impacts of Regulatory Options
This section provides an analysis of the prim ary environmental impacts (i.e., emission reductions), cost impacts and secondary environmental impacts related to Regulatory Option 2 for condensate storage vessels and Regulatory Option 3 for crude oil storage vessels which were selected as viable option s for setting standards for storage vessels.In addition, combined impacts for a typical storage vessel are presented.

7.5.3 Primary Environmental Impacts of Regulatory Options
Regulatory Option2 (condensate storage vessels) and 3 (crude oil storage vessels) were selected as options for setting standards for storage vessels as follows:

• Regulatory Option 2 (Condensate Storage Vessels) : Reduce emissions from condensate storage vessels with an average throughput greater than 1 bbl/day.

• Regulatory Option 3 (Cr ude Oil Storage Vessels) : Reduce emissions from crude oil storage vessels with an average throughput greater than 20 bbl/day

.

The number of storage vessels that would be subject to the regulatory options listed above are presented in Table s7

- 10 and 7

- 11 . I t was estimated that there would be 94 new or modified condensate storage vessels not otherwise subject to State regulationsand impacted by Regulatory Option 2 (condensate storage vessels).As shown in Table 7

- 11, 209 new or modified crude oil storage vesse ls not otherwise subject to State regulations would be impacted by Regulatory Option 3 (crude oil storage tanks).

Table 7

- 12 presents the nationwide emission reduction estimates for each regulatory option. Emissions reducti ons were estimated by applying 95 percent control efficiency to the VOC emissions presented in Table 7

- 6 for each storage vessel in the model condensate and crude oil tank batteries and multiplying by the number of impacted storage vessels. For Regulatory Option 2 (condensate storage vessels), the total nationwide VOC emission reduction was estimated to be 15,061 tons/year and 14,710 tons/year for Regulatory Option 3 (crude oil storage vessels).7

- 23 Table 7

- 12. Nationwide Impacts of Regulatory Options

Model Tank Batter y Number of

Sources subject to Regulatory Option a VOC

Emissions for a Typical Storage Vessel ( tons/year ) Capital

Cost forTypi cal Storage Vessel b ($) Annual Cost for a

Typical Storage Vessel b ($/yr) Nationwide Emission

Reductions ( tons/year ) c VOC Cost Effectiveness ($/ton) Methane Cost

Effectiveness ($/ton) Total Nationwide Costs (million $/year)

w ith out
s avings w i th

s avings VOC Methane d w ith out
s avings w i th

s avings w ith out

s avings w i th

s avings Capital

Cost Annual

without savings Annual

with savings Regulatory Option 2: Condensate Storage Vessels F 70 22.3 65,243 14,528 13,946 1,483 325 685 658 3129 3004 4.57 1.02 0.98 G 14 223 65,243 14,528 13,946 2,966 649 68 66 313 301 0.913 0.203 0.195 H 10 1117 65,243 14,528 13,946 10,612 2,322 14 13 62.6 60.1 0.652 0.145 0.139 Total for Regulatory Option 2 15,061 3,296 6.14 1.37 1.31 Regulatory Option 3: Crude Oil Storage Vessels G 123 28 65,243 14,528 13,946 3,272 716 546 524 2496 2396 8.02 1.79 1.71 H 86 140 65,243 14,528 13,946 11,438 2,503 109 104 499 479 5.61 1.25 1.20 Total for Regulatory Option 3 14,710 3,219 13.6 3.04 2.91 Combined Impacts e Typical Storage Vessel 304 103 65,243 14,528 13,946 29,746 6,490 149 143 680 652 19.8 4.41 4.24 Minor discrepancies may be due to rounding

a. Number of storage vessels in each model tank battery (refer to Table 7

- 6) determined to be subject to the regulatory option as outlined in Table 7

- 10. b. It was assumed for the purposes of estimating nationwide impacts that 50 percent of facilities would install a combustor and 50 percent a VRU.This accounts for the operatio nal difficulties of using a VRU. Capital and Annual Costs determined using th e average of costs presented in Tables 7

- 7 and 7

- 8.

c. Nationwide emission reductions calculated by applying a 95 percent emissions reduction to the VOC emissions for a typical sto rage vessel multiplied by the number of sources subject to the regulatory optio n. d. Methane Reductions calculated by applying the average Methane to VOC factor from the E&P Tanks Study (see Appendix A).Methane:VOC = 0.219

e. For purposes of evaluating NSPS impact, impacts were determined for an average storag e vessel by calculating total VOC emissions from all storage vessels and dividing by the total number of impacted storage vessels to obtain the average VOC emissions per storage vessel.7

- 24

7.5.4 Cost Impacts
Cost impacts of the individual control techniques ( VRU and combustors) were presented in S ection 7 .4. For both regulatory options, it was assumed that 50 percent of facilities would install a combustor and 50 percent a VRU. This accounts for the operational difficulties of using a VRU. Therefore, the avera ge capital cost of control for each storage vessel was estimated to be $65,243 (the average of the total capital investment for a VRU of $98,186 and $32,301 for a combustor from Tables 7

- 7 and 7

- 8, respectively ). Similarly, the average annual cost for a ty pical storage vessel was estimated to be $14,528/yr (average of the total annual cost for a VRU of $20,147/yr and $8,909/yr for a combustor
from Tables 7

- 7 and 7

- 8, respectively) without including any cost savings due to fuel sales and $13,946/yr (average of the total annual cost for a VRU of $18,983/yr and $8,909/yr for a combustorfrom
Tables 7

- 7 and 7

- 8, respectively) including cost savings.
Nationwide capital and annual costs were calculated by applying the number of storage vessels subject to the regula tory option. As shown in Table 7

- 12, the nationwide capital cost of Regulatory Option 2 (condensate storage vessels) was estimated to be $6.14 million and for RegulatoryOption 3 (crude oil storage vessels) nationwide capital cost was estimated to be $13.6 million.Total annual costs without fuel savings were estimated to be $1.37 million/yr for Regulatory Option 2 (condensate storage vessels) and $3.04 million/yr for Regulatory Option 3 (crude oil storage vessels ) . Total annual costs with fuel savings were e stimated to be $1.31 million/yr for Regulatory Option 2 (condensate storage vessels) and $2.91 million/yr for Regulatory Option 3 (crude oil storage vessels).

For purposes of evaluating the impact of a federal standard, impacts were determined for an avera ge storage vessel by calculating the total VOC emissions from all storage vessels and dividing by the total number of impacted storage vessels (304) to obtain the average VOC emissions per storage vessel (103 tons/year ). Therefore, the nationwide annual costs were estimated to be $4.41 million/yr. A total nationwide VOC emission reduction of 29,746 tons/year results in a cost effectiveness of $149/ton.

7.5.5 Nationwide Secondary Emission Impacts
Regulator y Options 2 (condensate storage vessels) and 3 (crude oil storage vessels) allow for the use of a combustor ; therefore the estimated nationwide secondary impacts are a result of combusting 50 percent of all storage vessel emissions

. The secondary impacts f or controlling a single storage vessel using a combustor are presented in Table 7

- 9. Nationwide secondary impacts are calculated by7

- 25

Table 7

- 13. Nationwide Secondary Combined Impacts for Storage Vessels

Pollutant Emissions per

Storage Vessel ( tons/year ) a Nationwide

Emissions ( tons/year ) b THC 0.0061 0.927 CO 0.0160 2.43 CO 2 5.62 854 NO X 2.95E

- 03 0.448 PM 5.51E

- 05 0.0084

a. Emissions per storage vessel presented in Table 7

- 9. b. Nationwide emissions calculated by assuming that 50 percent of the 304 impacted storage vessels would install a combustor.7

- 26

multiplying 50 percent of the estimated number of impacted storage vessels (152) by the secondary emissions and are presented in Tab le 7

- 13.

7.6 References

1

. National Emissions Standards for Hazardous Air Pollutants for Source Categories: Oil and Natural Gas Production and Natural Gas Transmission and Storage

– Background Information for Proposed Standards. U. S. Environmental Protection Agency, Research Triangle Park, NC. Publication No.EPA

- 453/R

- 94

- 079a. April 1997.

2

. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

– 2008. U.S. Environmental Protection Agency, Research Triangle Park, NC.Publication No .EPA 430

- R

- 10

- 006. April 15, 2010.

3

. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

– 2007. U.S. Environmental Protection Agency, Research Triangle Park, NC.Publication No.EPA 430

- R

- 09

- 004. April 15, 2009.

4

. Hendler, A., (URS Corporation), Nu nn, J. (COMM Engineering), and J. Lundeen (Trimeric Corporation).VOC Emissions from Oil and Condensate Storage Tanks

– Final Report.Prepared for Texas Environmental Research Consortium. The Woodlands, TX. October 31, 2006 (revised April 2, 2009)

5

. U.S. En vironmental Protection Agency. Lessons Learned from Natural Gas STAR Partners: Installing Vapor Recovery Units on Crude Oil Storage Tanks. Publication No.EPA 430

- B

- 03

- 015. October 2003.

6

. Gidney, B., and S. Pena, Hy

- Bon Engineering Company, Inc. Upstream Oil and Gas Storage Tank Project Flash Emissions Models Evaluation. Final Report.Prepared for Texas Commission on Environmental Quality and Eastern Research Group, Inc. July 16, 2009.

7

. Initial Economic Impact Analysis for Proposed State

- Only Revisions to the Air Quality Control Commission’s Regulation Number 7, “Emissions of Volatile Organic Compounds.” September 18, 2008.

8

. Pr oduction Tank Emissions Model. E&P TANK Version 2.0, User’s Manual.A Program for Estimating Emissions from Hydrocarbon Production Tanks.American Petroleum Institute. Software Number 4697. April 2000.

9

. Grubert, D., EC/R Incorporated, to B. Moore, Fuels and Incineration Group, U.S. Environmental Protection Agency, Research Triangle Park, NC. Summary of the October 12, 2010 Meeting Between the EPA andAmerican Petroleum Institute . July 28, 2011.

10

. U.S. Energy Information Administration. Table 4a.U.S. Crude Oil and Liquid Fuels Supply, Consumption, and Inventories . Available on the Internet at http://www.eia.gov/emeu/steo/pub/cf_tables/steotables.cfm?tableNumber=97

- 27

11

. Memorandum from Wilson, D., et al, ERG, to A. Pope, U.S. Environmental Protection Agency.Documentation for NEI Updates for Oil and Natura l Gas Production and Natural Gas Transmission and Storage.March 15, 2011.

12

. Economic Indicators: Chemical Engineering Plant Cost Index. Chemical Engineering Magazine.

13

. U.S. Environmental Protection Agency

. AP 42, Fifth Edition, Volume I, Chapter 13.5 In dustrial Flares.Office of Air Quality Planning & Standards. 1991

14

. U.S. Environmental Protection Agency. Air Pollution Control Technology Fact Sheet: FLARES. Clean Air Technology Center.

15

. Hendler, A., URS Corporation, Austin, TX, et al. VOC Emissions From Oil and Condensate Storage Tanks. Prepared for Texas Environmental Research Consortium, The Woodlands, TX. October 31, 2006 (revised April 2, 2009).8

- 1 8 .0 EQUIPMENT LEAKS
Leaks from components in the oil and natural gas sector are a source of pollutant emissions

. This chapter explains the causes for these leaks, and provides emission estimates for “model” facilities in the various segments of the oil and gas sector

. In addition, nationwide equipment leak emission estimates from new sources are estimated

. Programs that are designed to reduce equipment leak emissions are explained , along with costs, emission reductions, and secondary impacts

. Finally, this chapter discusses considerations in developing regulatory alternatives for equipment leaks.

8.1 Equipment Leak Description
There are several potential sources of equipment leak emission s throughout the oil and natural gas

sector

. Components such as pumps, valves, pressure relief valves, flanges, agitators, and compressors are potential sources that can leak due to seal failure

. Other sources, such as open

- ended lines, and sampling connec tions may leak for reasons other than faulty seals

. In addition, corrosion of welded connections, flanges, and valves may also be a cause of equipment leak emissions

. The following sub

sections describe potential equipment leak sources and the magnitude of the volatile emissions from typical facilities in the oil and gas industry.

Due to the large number of valves, pumps, and other components within oil and natural gas production, processing, and /or transmission facilities , total equipment leak VOC emission s from these components can be significant

. Tank batteries or production pads are generally small facilities as compared with other oil and gas operations, and are generally characterized by a small number of components

. Natural gas processing plants, espe cially those using refrigerated absorption, and transmission stations tend to have a large number of components.

8 .2. Equipment leak Emission Data and Emissions Factors

8 .2.1 Summary of Major Studies and Emission Factors
Emissions data from equipment leaks have been collected from chemical manufacturing and petroleum production to develop control strategies for reducing HAP and VOC emissions from these sources. 1 , 2 , 3 In the evaluation of the emissions and emission reduction options for equipment leaks , many of these studies were consulted. Table 8

- 1 presents a list of the studies consulted along with an indication of the type of information contained in the study.8

- 2

8 .2.2 Model Plants
Facilities in the oil and gas sector can consist of a variety of combinati ons of process equipment and components

. This is particularly true in the production segment of the industry, where “surface sites” can vary from sites where only a wellhead and associated piping is located to sites where a substantial amount of separation , treatment, and compression occurs

. In order to conduct analyses to be used in evaluating potential options to reduce emissions from leaking equipment, a model plant approach was used

. The following sections discuss the creation of these model plants.

Inf ormation related to equipment counts was obtained from a natural gas industry report

. This document provided average equipment counts for gas production, gas processing, natural gas transmission and distribution

. These average counts were used to develop m odel plants for wellheads , well pads, and gathering line and boosting stations in the production segment of the industry, for a natural gas processing plant, and for a compression/transmission station in the natural gas transmission segment

. These equipmen t counts are consistent with those contained in EPA’s analysis to estimate methane emissions conducted in support of the Greenhouse Gas Mandat ory Reporting Rule (s ubpart W), which was published in the Federal Register on November 30, 2010 (75 FR 74458), Th ese model plants are discussed in the following sections

.

8.2.2.1 Oil and Natural Gas Production
Oil and natural gas production varies from site

- to site

. Many production sites may include only a wellhead that is extracting oil or natural gas from the ground

. Other production sites consist of wellheads attached to a well pad

. A well pad is a site where the production, extraction, recovery, lifting, stabilization, separation and/ or treating of petroleum and/or natural gas (including condensate) occurs

. T hese sites include all equipment (including piping and associated components, compressors, generators, separators, storage vessels, and other equipment) associated with these operations. A well pad can serve one well on a pad or several wells on a pad. A w ellhead site consisting of only the wellhead and affiliated piping is not considered to be a well pad. The number of wells feeding into a well pad can vary from one to as many as 7 wells. Therefore, the number of components with potential for equipment lea ks can vary depending on the number of wells feeding into the production pad and the amount of processing equipment located at the site.8

- 3

Table 8

- 1 . Major Studies Reviewed for Consideration or Emissions and Activity Data

Report Name Affiliation Year of Report Activity

Factor (s) Emissions

Data Control

Options Greenhouse Gas Mandatory Reporting Rule and Technical Supporting Documents EPA 2010 Nationwide X X
Inventory of Greenhouse Gas Emissions and Sinks: 1990

- 2008 4 EPA 2010 Nationwide X

Methane Emissions from the Natural Gas Industry 5 6 7 Gas Research Institute / EPA 1996 Nationwide X X

Methane Emissions from the US Petroleum Industry (Draft) 8 EPA 1996 Nationwide X

Methane Emissions from the US Petroleum Industry 9 EPA 1999 Nationwide X

Oil and Gas Emission Inventories for Western States 10 Western Regional Air Partnership 2005 Regional X X

Recommendations for Improvements to the Central States Regional Air Partnership's Oil and Gas Emission Inventories 11 Central States Regional Air Partnership 2008 Regional X X

Oil and Gas Producing Industry in Your State 12 Independent Petroleum Association of America 2009 Nationwide

Emissions from Natural Gas Production in the Barnett Shale and Opportunities for Cost

- effective Improvements 13 Environmental Defense Fund 2009 Regional X X

Emissions from oil and Natural Gas Production Facilities 14 Texas Commission for Environmental Quality 2007 Regional X X

Petroleum and Natural Gas Statistical Data 15 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 16 EPA 1999 X X

Protocol for Equipment Leak Emission Estimates 17 EPA 1995 Nationwide X X8

- 4

In addition to wellheads and well pads, model plants were developed for gathering lines and boosting stations

. The gathering lines and boosting stations are sites that collect oil and gas from well pads and direct them to the gas processing plants

. These stations have similar equipment to well pads; however they are not directly connected to the wellheads

. The EPA/GRI report provided the average number of equipment located at a well pad and the average number of components for each of these pieces of equi pment. 4 The type of production equipment located

at a well pad include: gas wellheads, separators, mete rs/piping , gathering compressors, heaters, and dehydrators

. The types of components that are associated with this equipment include: valves,
connectors, o pen

- ended lines, and pressure relief valves

. Four m odel plants were developed for well pads and are presented in Table 8

- 2

. These model plants were developed starting with one, three, five and seven wellheads , and adding the average numberof other pieces o f equipment per wellhead

. Gathering compressors are not included at well pads and were included in the equipment for gathering lines and boosting stations

. Component counts for each of the equipment items were calculated using the average component counts for gas production equipment in the Eastern U.S and the Western U.S. for the EPA/GRI document. A summary of the component counts for oil and gas production well pads is presented in Table 8

- 3.
Gathering line and boosting station model plants were developed using the average equipment counts for oil and gas production. The average equipment count was assigned Model Plant 2 and Model Plants 1 and 3 were assumed to be equally distributed on either side of the average equipment count. Therefore, Model Plant 1 c an be assumed to be a small gathering and boosting station, and Model Plant 3 can be assumed to be a large gathering and boosting station. A summary of the model plant production equipment counts for gathering lines and boosting stations is provided in Tab le 8

- 4.
Component counts for each of the equipment items were calculated using the average component counts for gas production equipment in the Eastern U.S and the Western U.S. from the EPA/GRI document. The components for gathering compressors were include d in the model plant total counts, but the compressor seals were excluded. Compressors seals are addressed in a Chapter 6 of this document. A summary of the component counts for oil and gas gathering line and boosting stations are presented in Table 8

- 5.8

- 5

Table 8

- 2

. Average Equipment Count for Oil and Gas Production Well Pad Model Plant s

Equipment Model Plant 1 Model Plant 2 Model Plant 3 Gas Wellheads 1 5 48 Separators

--- 4 40 Meter/Piping

--- 2 24
In

- Line Heaters

--- 2 26 Dehydrators

--- 2 19 Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4

- 4 and Table 4

- 7 , June 1996. (EPA

- 600/R

- 96

- 080h)8

- 6

Table 8

- 3

. Average Component Count for Oil and Gas Pro duction Well Pad Model Plants

Component Model Plant 1 Model

Plant 2 Model

Plant 3 Model

Plant 4 Valve 9 122 235 348
Connectors 37 450 863 1,276 Open

- Ended Line 1 15 29 43
Pressure Relief Valve 0 5 10 15 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)8

- 7

Table 8

- 4

. Average Equipment Count for Oil and Gas Production Gathering Line and Boosting Station Model Plants
Equip ment Model Plant 1 Model Plant 2 Model Plant 3 Separators 7 11 15 Meter/Piping 4 7 10 Gathering Compressors 3 5 7
In

- Line Heaters 4 7 10 Dehydrators 3 5 7 Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4

- 4 and Table 4

- 7 , June 1996. (EPA

- 600/R

- 96

- 080h)8

- 8

Table 8

- 5. Average Component Count for Oil and Gas Production Gathering Line and Boosting Station Model Plants
Component Model Plant 1 Model Plant 2 Model Plant 3 Valve 547 906 1,265
Connectors 1,723 2,864 4,005 Open

- Ended Line 51 83 115
Pressure Relief Valve 29 48 67 DataSource: 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)8

- 9

8.2.2.2 Oil and Natural Gas Processing
Natural gas processing involves the removal of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or bot h. The types of process equipment used to separate the liquids are separators, glycol dehydrators, and amine treaters. In addition, centrifugal and/or reciprocating compressors are used to pressurize and move the gas from the processing facility to the

tra nsmission stations.
New Source Performance Standards (NSPS) have already been promulgated for equipment leaks at new natural gas processing plants (40 CFR Part 60, subpart KKK), and were assumed to be the baseline emissions for this analysis. Only one model plant was developed for the processing sector. A summary of the model plant production components counts for an oil and gas processing facility is provided in Table 8

- 6.

8.2.2.3 Natural Gas Transmission /Storage

Natural gas transmission/storage stations are facilities that use compressors that move natural gas at elevated pressure from production fields or natural gas processing facilities, in transmission pipelines, to natural gas distribution pipelines, or into storage . In addition, transmission stations may include equipment for liquids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compression operated by natural gas processing facilities are includ ed in the onshore natural gas processing segment and are excluded from this segment. This source category also does not include emissions from gathering lines and boosting stations. Component counts were obtained from the EPA/GRI report and are presented i n Table 8

- 7.

8 .3 Nationwide Emissions from New Sources

8 .3.1 Overview of Approach
Nationwide emissions were calculated by using the model plant approach for estimating emissions

. Baseline model plant emissions for the natural gas production, processing , and transmission sectors were calculated using the component counts and the component gas service emission factors. 5 Annual emissions were calculated assuming 8,760 hours of operation each year

. The emissions factors are provided for total organic compoun ds (TOC) and include non

- VOCs such as methane and ethane

. The emission factors for the production and processing sectors that were used to estimate the new source emissions are presented in Table 8

- 8

. Emission factors for the transmission sector are presen ted in8

- 10

Table 8

- 6. Average Component Count for Oil and Gas Pro cessing Model Plant

Component Gas Plant (non

- compressor components) Valve 1,392
Connectors 4,392 Open

- Ended Line 134
Pressure Relief Valve 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

- 11 Table 8

- 7. Average Component Count for a Gas TransmissionFacility

Component Processing Plant Component Count Valve 704
Connection 3,068 Open

- Ended Line 55
Pressure Relief Valve 14 Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4

- 16, June 1996. (EPA

- 600/R

- 96

- 080h)8

- 12

Table 8

- 8 Oil and Gas Production and Processing Operations Average Emissions Factors

Component Type Component Service Emission Factor (kg/hr/source) Valves Gas 4.5E

- 03
Connectors Gas 2.0E

- 04 Open

- Ended Line Gas 2.0E

- 03
Pressure Relief Valve Gas 8.8E

- 03 Data Source: EPA, Protocol for Equipment Leak Emission Estimates, Table 2

- 4, November 1995. (EPA

- 453/R

- 95

- 017)8

- 13

Table 8

- 9

. Emissions for VOC, hazardous air pollutants (HAP), and methane were calculated using TOC weight fractions. 6 A summary of the base line emissions for each of the sectors are presented in Table 8

- 10

.

8.3.2 Activity Data
Data from oil and gas technical documents and inventories were used to estimate the number of new sources for each of the oil and gas sectors. Information from the Ener gy Information Administration (EIA) was used to estimate the number of new wells, well pads, and gathering and boosting stations. The number of processing plants and transmission/storage facilities was estimated using data from the Oil and Gas Journal, and the EPA Greenhouse Gas Inventory. A summary of the steps used to estimate the new sources for each of the oil and gas sectors is presented in the following sections.

8.3.2.1 Well Pads
The EIA provided a forecast of the number of new conventional and unconventional gas wells for the Year 2015 for both exploratory and developmental wells. The EIA projected 19,097 conventional and unconventional gas wells in 2015. The number of wells was c onverted to number of well pads by dividing the total number of wells by the average number of wells serving a well pad which is estimated to be 5. Therefore, the number of new well pads was estimated to be 3,820. The facilities were divided into the model plants assuming a normal distribution of facilities around the average model plant (Model Plant 2).

8.3.2.2 Gathering and Boosting
The number of new gathering and boosting stations was estimated using the current inventory of gathering compressors listed in the EPA Greenhouse Gas Inventory. The total number of gathering compressors was listed as 32,233 in the inventory. The GRI/EPA document does not include a separate list of compressor counts for gathering and boosting stations, but it does list the aver age number of compressors in the gas production section. It was assumed that this average of 4.5 compressors for gas production facilities is applicable to gathering and boosting stations. Therefore, using the inventory of 32,233 compressors and the averag e number of 4.5 compressors per facility, we estimated the number of gathering and boosting stations to be 7,163. To estimate the number of new gathering and boosting stations, we used the same increase of 3.84 percent used to estimate well pads to estimat e the number of new gathering and boosting stations. This provided an estimate of 275 new gathering and boosting8

- 14 Table 8

- 9 Oil and Gas Transmission/Storage Average Emissions Factors

Component Type Component Service Emission Factor (kg/hr/source) Valves Gas 5.5E

- 03
Connectors Gas 9.3E

- 04 Open

- Ended Line Gas 7.1E

- 02
Pressure Relief Valve Gas 3.98E

- 02 Data Source: EPA/GRI, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks, Table 4

- 1 7 , June 1996. (EPA

- 600/R

- 96

- 080h)8

- 15

Table 8

- 10

. Baseline Emissions for the Oil and Gas Production, Processing, and Transmission/Storage Model Plants

Oil and Gas Sector Model Plant TOC Emissions (Tons/yr) Methane

Emissions (Tons/yr) VOC Emissions

(Tons/yr) HAP Emissions

(Tons/yr)

Well Pads 1 0.482 0.335 0.0930 0.00351
2 13.3 9.24 2.56 0.0967
3 139 96.5 26.8 1.01

Gathering & Boosting 1 30.5 21.2 5.90 0.222
2 50.6 35.2 9.76 0.368
3 70.6 49.1 13.6 0.514 Processing 1 74.0 51.4 14.3 0.539 Transmission/Storage 1 108.1 98.1 2.71 0.08068

- 16

stations that would be affected sources under the proposed NSPS. The new gathering and boosting stations were assumed to be normally distributed around the average model plant (Model Plant 2).

8.3.2.3 Processing Facilities
The number of new processing fac ilities was estimated using gas processing data from the Oil and Gas Journal

. The Oil and Gas Journal Construction S urvey currently shows 6,303 million cubic feet of gas per day (MMcf/day) additional gas processing capacity in various stages of development

. The OGJ Gas Processing Survey shows that there is 26.9 trillion cubic feet per year (tcf/year) in existing capacity, with a current th roughput of 16.6 tcf/year or 62 percent utilization rate

. If the utilization rate remains constant, the new construction would add approximately 1.4 tcf/year to the processing system

. This would be an increase of 8.5 percent to the processing sector

. The recent energy outlook published by the EIApredict s a 1.03 tcf/year increase in natural gas processing from 21.07 to22.104 tcf/year

. This w ould be an annual increase of 5 percent over the next five years

.

The EPA Greenhouse Gas Inventory estimates the number of existing processing facilities to be 577 plants operating in the U.S

. Based on the projections provided in Oil and Gas Journal and EIA, it was assumed that the processin g sector would increase by 5 percent annually

. Therefore the number of new sources was estimated to be 29 new processing facilities in the U.S.

8.3.2.4 Transmission/Storage Facilities

The number of new transmission and storage facilities was estimated using the annual growth rate of 5 percent used for the processing sector and the estimated number of existing transmission and storage facilities in the EPA Greenhouse Inventory

. The inventory estim ates 1,748 transmission stations and 400 storage facilities for a total of 2,148

. Therefore, the number of new transmission/storage facilities was estimated to be 107.

8.3.3 Emission Estimates
Nationwide emission estimates for the new sources for well pads , gathering and boosting, processing, and transmission/storage are summarized in Table 8

- 11

. For well pads and gathering and boosting stations, the numbers of new facilities were assumed to be normally distributed across the range of model plants.8

- 17 Table 8

- 11

. Nationwide Baseline Emissions for New Sources

Oil and Gas Sector Model Plant Number of New Facilities TOC

Emissions (t ons/yr) Methane

Emissions (t ons/yr) VOC

Emissions (t ons/yr) HAP

Emission s (t ons/yr)

Well Pads 1 605 292 203 56.3 2.12
2 2, 610 34 ,6 87 24 ,1 16 6,682 252
3 605 84,035 58,389 16,214 612
Total 3 , 820 119 , 014 82,708 22,952 866

Gathering & Boosting 1 44 1, 312 912 254 9.55
2 18 7 9 , 513 6 , 618 1, 835 69.2
3 44 3,106 2,160 598 22.6
Total 2 75 1 3 , 931 9 , 690 2, 687 1 01 Processing 1 29 2,146 1,490 415 15.6 Transmission/Storage 1 107 11,567 10,497 290 8.628

- 18

8.4 Control Techniques

8 .4.1 Potential Control Techniques
EPA has determined that leaking equipment, such as valves, pumps, and connectors, are a significant source of VOC and HAP emissions from oil and gas facilities. The following section describes the techniques used to reduce emissions from these sources.
The most effective control technique for equipment leaks is the implementation of a leak detection and repair program (LDAR). Emissions reductions from implementing an LDAR program can potentially reduce product losses, increase safety for workers and operators, decrease exposure of hazardous chemicals to the surrounding community, reduce emis sions fees, and help facilities avoid enforcement actions. The elements of an effective LDAR program include:

 Identifying Components;

 Leak Definition;

 Monitoring Components;

 Repairing Components; and

 Recordkeeping.
The primary source of equipment leak emissions from oil and gas facilities are from valves and

connectors , because these are the most prevalent components and can number in the thousands

. The major cause of emissions from valves and connectors is a seal or gasket failure du e to normal wear or improper maintenance . A leak is detected whenever the measured concentration exceeds the threshold standard (i.e., leak definition) for the applicable regulation. Leak definitions vary by regulation, component type, service (e.g., light liquid, heavy liquid, gas/vapor), and monitoring interval. Most NSPS regulations have a leak definition of 10,000 ppm, while many NESHAP regulations use a 500

- ppm or 1,000

- ppm leak definition. In addition, some regulations define a leak based on visual in spections and observations (such as fluids dripping, spraying, misting or clouding from or around components), sound (such as hissing), and smell.8

- 19

For many NSPS and NESHAP regulations with leak detection provisions, the primary method for monitoring to det ect leaking components is EPA Reference Method 21 (40 CFR Part 60, Appendix A)

. Method 21 is a procedure used to detect VOC leaks from process equipment using toxic vapor analyzer (TVA) or organic vapor analyzer (OVA)

. In addition, other monitoring tools s uch as; infrared camera, soap solution, acoustic leak detection, and electronic screening device, can be used to monitor process components

.

In optical gas imaging , a live video image is produced by illuminating the view area with laser light in the infra red frequency range

. In this range, hydrocarbons absorb the infrared light and are revealed as a dark image or cloud on the camera

. The passive inf r ared cameras scan an area to produce images of equipment leaks from a number of sources

. Active infrared cam eras point or aim an infrared beam at a potential source to indicate the presence of equipment leaks

. The optical imaging camera is easy to use and very efficient in monitoring many components in a short amount of time

. However, the optical imaging camera cannot quantify the amount or concentration of equipment leak

. To quantify the leak, the user would need to measure the concentration of the leak using a TVA or OVA

. In addition, the optical imaging camera has a high upfront capital cost of purchasing the camera

. Acoustic leak detectors measure the decibel readings of high frequency vibrations from the noise of leaking fluids from equipment leaks using a stethoscope

- type device

. The decibel reading, along with the type of fluid, density, system pressure, a nd component type can be correlated into leak rate by using algorithms developed by the instrument manufacturer

. The acoustic detector does not decrease the monitoring time because components are measured separately, like the OVA or TVA monitoring

. The

acc uracy of the measurements using the acoustic detector can also be questioned due to the number of variables used to determine the equipment leak emissions.

Monitoring intervals vary according to the applicable regulation, but are typically weekly, monthly, quarterly, and yearly

. For connectors, the monitoring interval can be every 1, 2, 4, or 8 years

. The monitoring interval depends on the component type and periodic leak rate for the component type

. Also, many LDAR requirements specify weekly visual inspec tions of pumps, agitators, and compressors for indications of liquids leaking from the seals

. For each component that is found to be leaking , the first attempt at repair is to be made no later than five calendar days after each leak is detected. First attempts at repair include, but are not limited to, the following best practices, where practicable and appropriate:

 Tightening of bonnet bolts ;8

- 20

 Replacement of bonnet bolts ;

 Tightening of packing gland nuts ; and

 Injection of lubricant into lubricated packi ng

.
On c e the component is repaired; it should be monitored daily over the next several days to ensure the leak has been successfully repaired

. Another method that can be used to repair component is to replace the leaking component with “leakless” or other technologies

. The LDAR recordkeeping requirement for each regulated process requires that a list of all ID numbers be maintained for all equipment subject to an equipment 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, equipment design specifications (including dates and descriptions of any changes), and piping and instrumentation diagrams should also be maintaine d with the results of performance testing and leak detection monitoring, which may include leak monitoring results per the leak frequency, monitoring leakless equipment, and non

- periodic event monitoring

.

Other factors that can improve the efficiency of a n LDAR program that are not addressed by the standards include training programs for equipment monitoring personnel and tracking systems that address the cost efficiency of alternative equipment (e.g., competing brands of val ves in a specific application).

The first LDAR option is the implementation of a subpart VVa LDAR program

. This program is similar to the VV monitoring, but finds more leaks due to the lower leak definition, thereby achieving better emission reductions

. The VVa LDAR program requires the annual monitoring of connectors using a n 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 defini tion)

. The monitoring of each of the equipment types were also analyzed as a possible option for reducing equipment leak emissions. The second option involves using the monitoring requirements in subpart VVa for each type of equipment which include: valves ; connectors; pressure relief devices; and open

- ended lines for each of the oil and gas sectors.

The third option that was investigated was the implementation of a LDAR program using an optical gas imaging system

. This option is currently available as an al ternative 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 the optical gas imaging system and an8

- 21

annual monitoring of a ll components using a Method 21 monitoring device

. The Method 21 monitoring allows the facility to quantify emissions from equipment leaks, since the optical gas imaging system can only provide the magnitude of the equipment leaks.

A fourth option that was investigated is a modification of the 40 CFR Part 60, subpart A alternative work practice

. The alternative work practice was modified by removing the required annual monitoring using a Method 21 instrument

. This option only requires the monthly monitoring of components using the optical gas imaging system.

8.4.2 Subpart VVa LDAR Program

8.4.2.1 Description
The subpart VVa LDAR requires the monitoring of pumps, compressors, pressure relief devices, sampling connection systems, open

- ended lines, valves, and c onnectors

. 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 par ts per million by volume (ppmv)

. Valves are monitored monthly, connectors are monitored annually, and open

- ended lines and pressure relief valves have no monitoring requirements, but are required to operate without any d etectable emissions

. Compressors are not included in this LDAR option and are regulated separately.

8.4. 2 .2 Effectiveness
The control effectiveness of the 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

. A summary of the chemical manufacturing and petroleum refinery control effectiveness for each of the components is shown in Table 8

- 12

. As shown in the table 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

. Descriptions of the frequency of monitoring and leak definition are described further below.
Monitoring Frequency: The monitoring frequency is the number of times eac h component is checked for leaks

. For an example, quarterly monitoring requires that each component be checked for leaks 4 times per year, and annual monitoring requires that each component be checked for leaks once per year

. As shown in Table 8

- 12, monthl y monitoring provides higher control effectiveness than quarterly8

- 22

Table 8

- 12. Control Effectiveness for an LDAR program at a Chemical Process Unit and a Petroleum Refinery

Equipment Type and Service Control Effectiveness (% Reduction) Monthly Monitoring 10,000 ppmv Leak Definition Quarterly

Monitoring 10,000 ppmv Leak Definition 500 ppm Leak

Definition a

Chemical Process Unit
Valves

– Gas Service b 87 67 92

Valves

– Light Liquid Service c 84 61 88

Pumps

– Light Liquid Service c 69 45 75

Connectors

– All Services

--- --- 93 Petroleum Refinery
Valves

– Gas Service b 88 70 96

Valves

– Light Liquid Service c 76 61 95

Pumps

– Light Liquid Service c 68 45 88

Connectors

– All Services

--- --- 81 Source: Protocol for Equipment Leak Emission Estimates, EPA

- 453/R

- 95

- 017, Nov 1995.
a. Control effectiveness attributable to the HON

- negotiated equipment leak regulation (40 CFR 63, Subpart H) is estimated based on equipment

- specific leak definitions and performance levels. However, pumps subj ect to the HON at existing process units have a 1,000 to 5,000 ppm leak definition, depending on the type of process. b. Gas (vapor) service means the material in contact with the equipment component is in a gaseous state at the process operating conditions.
c. Light liquid service means the material in contact with the equipment component is in a liquid state in which the sum of the concentration of individual constituents with a vapor pressure above 0.3 kilopascals (kPa) at 20°C is greater than or equal to 20% by weight.8

- 23

monitoring. This is because leaking components are found and repaired more quickly, which lowers the amount of emissions that are leaked to the atmosphere.

Leak Definition: The leak definition describes the local VOC concentration at the surf ace 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 concentration generally increases the number of leaks found during a monitoring period, which generally increases the number of leaks that are repaired

. The control effectiveness for the well pad, gathering and boosting stations, processing facilities, and transmissions and storage facilities were calculated using the LDAR control effectiveness and leak fraction equations for oil and gas production operation units in the EPA equipment leaks protocol document

. The leak fraction equation uses the average leak rate (e.g., the component emission factor) and leak definition to calculate the leak fraction. 7 This leak fraction is used in a steady state set of equations to determine the final leak rate after implementing a LDAR program. 8 The initial leak rate and the final leak rate after implementing a LDAR program were then us ed to calculate the control effectiveness of the program

. The control effectiveness for implementing a subpart VVa LDAR program

was calculated to be 93.6 perccent for valves, 95.9 percent for connectors, 100 percent for open

- ended lines, and 100 percent fo r pressure relief devices

.

8.4. 2 .3 Cost Impacts
Costs were calculated using a LDAR cost spreadsheet develop edfor estimating capital and annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing industry

. The costs are based on the following assumptions:

 Subpart VVa monitoring frequency and leak definition were used for processing plants since they are already required to do subpart VV requirements. Connectors were assumed to be monitored over a 4

- year period after initial annual compliance monitoring

.

 Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for pressure relief valve disks, $3,852 for pressure relief valve disk holder and valves, and $102 for open

ended lines.

 Subsequent monitoring cos ts are $1.50 for valves and connectors, $2.00 for pressure relief valve disks, and $5.00 for pressure relief valve d evices and open

- ended lines.

 A wage rate of $30.46 per hour was used to determine labor costs for repair

.8

- 24

 Administrative costs and initial p lanning and training costs are based on the Miscellaneous Organic NESHAP (MON) analysis

. The costs were based on 340 hours for planning and training and 300 hours pe r year for reporting and administrative tasks at $48.04 per hour

.

 The capital cost also inc ludes $14,500 for a data collection system for maintaining the inventory and monitoring records for the components at a facility.

 Recovery credits were calculated assuming the methane reduction has a value of $4 .00 per 1000 standard cubic feet.

It was assu med that a single Method 21 monitoring device could be used at multiple locations for production pads, gathering and boosting stations, and transmission and storage facilities

. To calculate the shared cost of the Method 21 device, the time required to moni tor a single facility was estimated

. For production pads and gathering and boosting stations, it was assumed that it takes approximately 1 minute to monitor a single component, and approximately 451 components would have to be monitored at an average facil ity in a month

. This calculates to be 451 minutes or 7.5 hours per day

. Assuming 20 working days in a typical month, a single Method 21 device could monitor 20 facilities

. Therefore, the capital cost of the Method 21 device ($6,500) was divided by 20 to ge t a shared capital cost of $325 per facility

. It was assumed for processing facilities that the full cost of the Method 21 monitoring device would apply to each individual plant

. The transmission and storage segment Method 21 device cost was estimated usin g assuming the same 1 minute per component monitoring time

. The average number of components that would need to be monitored in a month was estimated to be 1,440, which calculates to be 24 hours of monitoring time or 3 days

. Assuming the same 20 day work m onth, the total number of facilities that could be monitored by a single Method 21 device is 7

. Therefore, the shared cost of the Method 21 monitoring device was calculated to be $929 per site.

A summary of the capital and annual costs and the cost effectiveness for each of the model plants in the oil and gas sectors are provided in Table 8

- 13

. In addition to the full subpart VVa LDAR monitoring, a component by component LDAR analysis was perform ed for each of the oil and gas sectors using the component count for an average size facility

. This Model Plant 2 f or well pads , Model Plant 2 for gathering and boosting stations , and Model Plant 1 for processing plants and transmission and storage facilit ies.8

- 25 Table 8

- 1 3

. Summary of the Model Plant C ost Effectiveness for the Subpart VVa Option

Model Plant Annual Emission Reductions (tons/year) Capital Cost ($) Annual Cost

($/year) Cost Effectiveness ($/ton)
VOC HAP Methane without savings with savings VOC HAP Methane
Well Pads
1 0.0876 0.00330 0.315 $15,418 $23,423 $23,350 $267,386 $7,088,667 $74,253
2 2.43 0.0915 8.73 $69,179 $37,711 $35,687 $15,549 $412,226 $4,318
3 25.3 0.956 91.3 $584,763 $175,753 $154,595 $6,934 $183,835 $1,926 Gathering and Boosting Stations
1 5.58 0.210 20.1 $148,885 $57,575 $52,921 $10,327 $273,769 $2,868
2 9.23 0.348 33.2 $255,344 $84,966 $77,259 $9,203 $243,987 $2,556
3 12.9 0.486 46.4 $321,203 $105,350 $94,591 $8,174 $216,692 $2,270 Processing Plants
1 13.5 0.508 48.5 $7,522 $45,160 $33,915 $3,352 $88,870 $931 Transmission/Storage Facilities
1 2.62 0.0780 94.9 $94,482 $51,875 N/A $19,769 $665,155 $546
Note: Transmission and storage facilities do not own the natural gas; therefore they do not receive any cost benefits f rom reducing the amount of natural gas as the result of equipment leaks

.8

- 26

The component c osts were calculated using a LDAR cost spreadsheet develop edfor estimating capital and annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing industry. The costs are based on the following assumptions:

 Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for pressure relief valve disks, $3,852 for pressure relief valve disk holder and valves, and $102 for open

ended lines.

 Subsequent monitoring costs are $1.50 for valves and connectors, $2.00 for pressure relief valve disks, and $5.00 for pressure relief valve devices and open

- ended line s.

 A wage rate of $30.46 per hour was used to determine labor costs for repair.

 Administrative costs and initial planning and training costs are were included for the component option and are based on the Miscellaneous Organic NESHAP (MON) analysis. The co sts were based on 340 hours for planning and training and 300 hours per year for reporting and administrative tasks at $48.04 per hour.

 The capital cost for purchasing a TVA or OVA monitoring system was estimated to be $6,500.

The co mponent control effect iveness for the subpart VVa component option were 93.6 percent for valves, 95.9 percent for connectors, 100 percent for open

- ended lines, and 100 percent for pressure relief devices. These were the same control effectiveness’s that were used for the subpar t VVa facility option. The control effectiveness for the modified subpart VVa option with less frequent monitoring was estimated assuming the control effectiveness follows a hyperbolic curve or a 1/x relationship with the monitoring frequency. Using this a ssumption the component cost effectiveness’s were determined to be 87.2 percent for valves, 81.0 percent for connectors, 100 percent for open

- ended lines, and 100 percent for pressure relief devices. The assumption is believed to provide a conservative est imate of the control efficiency based on less frequent monitoring. A summary of the capital and annual costs and the cost effectiveness for each of the components for each of the oil and gas sectors are provided in Tables 8

- 14, 8

- 15, 8

- 16, and 8

- 17.

8.4. 2 .4 Secondary Impacts
The implementation of a LDAR program reduces pollutant emissions from equipment leaks. No secondary gaseous pollutant emissions or wastewater are generated during the monitoring and repair of equipment leaks. Therefore, there are no secondary impacts expected from the implementation of a LDAR program.8

- 27 Table 8

- 1 4

. Summary of Component C ost Effectiveness for Well Pads for the Subpart VVa Option s

Component Average

Number of Components Monitoring

Frequency (Times/yr) Annual Emission Reductions (tons/year) Capital Cost ($) Annual

Cost ($/yr) Cost

- effectiveness ($/ton)
VOC HAP Methane VOC HAP Methane Subpart VVa Option
Valves 235 12 1. 84 0. 0696 6. 64 $11, 175 $ 27 , 786 $ 1 5 ,063 $ 399 , 331 $ 4 , 183
Connectors 863 1/0.25 a 0. 308 0.0116 1.11 $ 7,830 $ 22,915 $ 74 , 283 $ 1,969 , 328 $ 20 , 628

PRD 10 0 0.164 0.00619 0.591 $ 48 , 80 0 $ 29 , 609 $ 180 , 537 $ 4,786 , 215 $ 50 , 135
OEL 29 0 0.108 0.00408 0.389 $ 9 , 4 58 $ 22,915 $ 211 ,9 92 $ 5,620 , 108 $ 58 , 870 Modified Subpart VVa

– Less Frequent Monitoring
Valves 235 1 1. 31 0.0 4 96 4.73 $11,175 $ 23 , 436 $ 17 , 828 $ 472 , 640 $ 4 , 951
Connectors 863 1/0. 1 25 b 0. 261 0.0 0983 0.938 $7, 830 $ 22 , 740 $ 87 , 277 $ 2,313 , 795 $ 24 , 237

PRD 5 0 0.164 0.00619 0.591 $48,800 $29,609 $180,537 $4,786,215 $50,135
OEL 29 0 0.108 0.00408 0.389 $9,458 $22,915 $211,992 $5,620,108 $58,870 Minor discrepancies may be due to rounding.
a. I t was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter. b. It was assumed that all the connectors are monitored in the first year for initial compliance and every 8 years thereafter.8

- 28

Table 8

- 1 5

. Summary of Component C ost Effectiveness for Gathering and Boosting Stations for the Subpart VVa Options

Component Aver age

Number of Components Monitoring

Frequency (Times/yr) Annual Emission Reductions (tons/year) Capital Cost ($) Annual

Cost ($/yr) Cost

- effectiveness ($/ton)
VOC HAP Methane VOC HAP Methane Subpart VVa Option

Valves 906 12 7.11 0.268 25.6 $24,524 $43,234 $6,079 $161,162 $1,688

Connectors 2,864 1/0.25 a 1.02 0.0386 3.69 $10,914 $24,164 $23,603 $625,752 $6,555

PRD 48 0 0.787 0.0297 2.83 $195,140 $57,091 $72,523 $1,922,648 $20,139

OEL 83 0 0.309 0.0117 1.11 $14,966 $23,917 $77,310 $2,049,557 $21,469 Modified Subpart VVa

– Less Frequent Monitoring

Valves 906 1 5.07 0.191 18.2 $24,524 $24,461 $ 5 , 221 $1 38 , 417 $1, 450

Connectors 2,864 1/0.125 b 0.865 0.0326 3.11 $10,914 $23,584 $2 7 , 274 $ 723 , 067 $ 7 ,5 74

PRD 48 0 0.787 0.0297 2.83 $195,140 $57,091 $72,523 $1,922,648 $20,139

OEL 83 0 0.309 0.0117 1.11 $14,966 $23,917 $77,310 $2,049,557 $21,469 Minor discrepancies may be due to rounding.
a. It was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter. b. It was assumed that all the connectors are monitored in the first year for initial compliance and every 8 years thereafter.8

- 29

Table 8

- 1 6

. Summary of Incremental Component C ost Effectiveness for Processing Plants for the Subpart VVa Option

Component Average

Number of Components Monitoring

Frequency (Times/yr) Annual Emission Reductions (tons/year) Capital Cost ($) Annual

Cost ($/yr) Cost

- effectiveness ($/ton)
VOC HAP Methane VOC HAP Methane Incremental Component Cost for Subpart VV to Subpart VVa Option
Valves 1,392 12 10.9 0.412 39.3 $6,680 $1,576 $144 $3,824 $40
Connectors 4,392 1/0.25 a 1.57 0.0592 5.65 $2,559 $6,845 $4,360 $115,585 $1,211

PRD 29 0 0.499 0.0188 1.80 $0 $0 $0 $0 $0
OEL 134 0 0.476 0.0179 1.71 $0 $0 $0 $0 $0 Minor discrepancies may be due to rounding.
a. It was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter.8

- 30

Table 8

- 1 7

. Summary of Component C ost Effectiveness for Transmission and Storage Facilities for the Subpart VVa Options

Component Average

Number of Components Monitoring

Frequency (Times/yr) Annual Emission Reductions (tons/year) Capital Cost ($) Annual

Cost ($/yr) Cost

- effectiveness ($/ton)
VOC HAP Methane VOC HAP Methane Subpart VVa Option
Valves 673 12 0.878 0.0261 31.8 $19,888 $37,870 $43,111 $1,450,510 $1,192
Connectors 3,068 1/0.25 a 0.665 0.0198 24.1 $11,229 $24,291 $36,527 $1,229,005 $1,010

PRD 14 0 0.133 0.00397 4.83 $61,520 $32,501 $243,525 $8,193,684 $6,732
OEL 58 0 0.947 0.0282 34.3 $12,416 $23,453 $24,762 $833,137 $684 Modified Subpart VVa

– Less Frequent Monitoring
Valves 673 1 0.626 0.0186 22.6 $19,888 $25,410 $40,593 $1,365,801 $1,122
Connectors 3,068 1/0.125 b 0.562 0.0167 20.3 $11,229 $23,669 $42,140 $1,417,844 $1,165

PRD 14 0 0.133 0.00397 4.83 $61,520 $32,501 $243,525 $8,193,684 $6,732
OEL 58 0 0.947 0.0282 34.3 $12,416 $23,453 $24,762 $833,137 $684 Minor discrepancies may be due to rounding.
a. It was assumed that all the connectors are monitored in the first year for initial compliance and every 4 years thereafter. b. It was assumed that all the connectors are monitored in the first year for initial compliance and every 8 years thereafter.8

- 31

8.4.3 LDAR with Optical Gas Imaging

8.4. 3 .1 Description
The alternative work practice for equipment leaks in §60.18 of 40 CFR Part 60, subpart A allows the use of an optical gas imaging system to monitor leaks from components

. Thi s LDAR requires monthly monitoring and repair of components using an optical gas imaging system, and annual monitoring of components using a Method 21 instrument

. This requirement does not have a leak definition because the optical gas imaging system can only measure the magnitude of a leak and not the concentration

. However, this alternative work practice does not require the repair of leaks below 500 ppm

. Compressors are not included in this LDAR option and are discussed in Chapter 6 of this document

.

8.4

. 3 .2 Effectiveness
No data was found on the control effectiveness of the alternative work practice

. It is believed that this option would provide the same control effectiveness as the subpart VVa monitoring program

. Therefore, the control effectiveness ’s f or implementing a n alternative work practice was 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

.

8.4. 3 .3 Cost Impacts
Costs were calculated using a LDAR cos t spreadsheet develop edfor estimating capital and annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing industry

. The costs are based on the following assumptions:

 Initial monitoring and setup costs are $17.70 for valves, $1.1 3 per connector, $78.00 for pressure relief valve disks, $3,852 for pressure relief valve disk holder and valves, and $102 for open

ended lines.

 Monthly optical gas imaging monitoring costs are estimated to be $ 0 .50 for valves , connectors, pressure relief valve d evices , and open

- ended lines.

 Annual monitoring costs using a Method 21 device are estimated to be $1.50 for valves and connectors, $2.00 for pressure relief valve disks, and $5.00 for pressure relief devices and open

ended lines.

 A wage rate of $30 .46 per hour was used to determine labor costs for repair.8

- 32

 Administrative costs and initial planning and training costs are based on the Miscellaneous Organic NESHAP (MON) analysis

. The costs were based on 340 hours for planning and training and 300 hours per year for reporting and administrative tasks at $48.04 per hour.

 The capital cost also includes $14,500 for a data collection system for maintaining the inventory and monitoring records for the components at a facility.

 Recovery credits were calculated assuming the methane reduction has a value of $4 .00 per 1000 standard cubic feet.
It was assumed that a single optical gas imaging and a Method 21 monitoring device could be used at multiple locations for production pads, gathering and boosting stations, and transmission and storage facilities

. To calculate the shared cost of the optical gas imaging system and the Method 21 device, the time required to monitor a single facility was estimated

. For production pads and gathering and boosting stations, it was assumed that 8 production pads could be monitored per day

. This means that 160 production facilities could be monitored in a month

. In addition, it was assumed 13 gathering and boosting station would service these wells and could be monitored during the sa me month for a total of 173 facilities

. Therefore, the capital cost of the optical gas imaging system (Flir Model GF320, $85,000) and the Method 21 device ($6,500) was divided by 173 to get a shared capital cost of $529 per facility

. It was assumed for pro cessing facilities that the full cost of the optical gas imaging system and the Method 21 monitoring device would apply to each individual plant

. The transmission and storage segment Method 21 device cost was estimated assuming th at one facility could be m onitored in one hour, and the travel time between facilities was one hour

. Therefore, in a typical day 4 transmission stations could be monitored in one day

. Assuming the same 20 day work month, the total number of facilities that could be monitored by a s ingle optical gas imaging system and Method 21 device is 80

. Therefore, the shared cost of the Method 21 monitoring device was calculated to be $ 1,144 per site.
A summary of the capital and annual costs and the cost effectiveness for each of the model pla nts in the oil and gas sectorusing the alternative work practice monitoring is provided in Table 8

- 18. A component cost effectiveness analysis for the alternative work practice was not performed, because the optical gas imaging system is not conducive to c omponent monitoring, but is intended for facility

- wide monitoring.

8.4. 3.4 Secondary Impacts
The implementation of a LDAR program reduces pollutant emissions from equipment leaks. No secondary gaseous pollutant emissions or wastewater are generated during the monitoring and repair of8

- 33

Table 8

- 1 8. Summary of the Model Plant C ost Effectiveness for the Optical Gas Imaging and Method 21 Monitoring Option

Model Plant Annual Emission Reductions (tons/year) Capital Cost ($) Annual Cost

($/yea r) Cost Effectiveness ( $/ton)
VOC HAP Methane without savings with savings VOC HAP Methane
Well Pads
1 0.0876 0.00330 0.315 $15,428 $21,464 $21, 391 $245,024 $6,495,835 $68,043
2 2.43 0.0915 8.73 $64,858 $39,112 $37, 088 $16,127 $427,540 $4,478
3 25.3 0.956 91.3 $132,891 $135,964 $11 4 , 807 $5,364 $142,216 $1,490 Gathering and Boosting Stations
1 5.58 0.210 20.1 $149,089 $63,949 $ 59 , 295 $11,470 $304,078 $3,185
2 9.23 0.348 33.2 $240,529 $93,210 $8 5 , 503 $10,096 $267,659 $2,804
3 12.9 0.486 46.4 $329,725 $121,820 $11 1 , 060 $9,451 $250,567 $2,625 Processing Plants
1 13.5 0.508 48.5 $92,522 $87,059 $75,813 $6,462 $171,321 $1,795 Transmission/Storage Facilities
1 2.62 0.0780 94.9 $20,898 $51,753 N/A $19,723 $663,591 $545 Minor discrepancies may be due to rounding. Note: Transmission and storage facilities do not own the natural gas; therefore cost benefits from reducing the amount of nat ural gas as the result of equipment leaks was not estimated for the transmission segment..8

- 34

equipment leaks. Therefore, there are no secondary impacts expected from the implementation of a LDAR program.

8.4.4 Modified Alternative Work Practice with Optical Gas Imaging

8.4.4.1 Description

The modi fied alternative work practice for equipment leaks in §60.18 of 40 CFR Part 60, subpart A allows the use of an optical gas imaging system to monitor leaks from components, but removes the requirement of the annual Method 21 device monitoring. Therefore, th e modified work practice would require only monthly monitoring and repair of components using an optical gas imaging system. This requirement does not have a leak definition because the optical gas imaging system can only measure the magnitude of a leak an d not the concentration. However, this alternative work practice does not require the repair of leaks below 500 ppm. Compressors are not included in this LDAR option and are regulated separately.

8.4. 4 .2 Effectiveness
No data was found on the control effectiveness of this modified alternative work practice. However, it is believed that this option would provide the similar control effectiveness and emission reductions as the subpart VVa monitoring program. Therefore, th e control effectiveness’s for implementing an alternative work practice was 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.

8.4. 4 .3 Cost Impacts

Costs were calculated using a LDAR cost spreadsheet develop edfor estimating capital and annual costs for applying LDAR to the Petroleum Refinery and Chemical Manufacturing industry

. The costs are based on the following assumptions:

 Initial monitoring and setup costs are $17.70 for valves, $1.13 per connector, $78.00 for pressure relief valve disks, $3,852 for pressure relief valve disk holder and valves, and $102 for open

ended lines.

 Monthly optical gas imaging monitoring costs are estimated to be $0.50 for valves, c onnectors, pressure relief valve devices, and open

- ended lines.

 A wage rate of $30.46 per hour was used to determine labor costs for repair.8

- 35

 Administrative costs and initial planning and training costs are based on the Miscellaneous Organic NESHAP (MON) an alysis

. The costs were based on 340 hours for planning and training and 300 hours per year for reporting and administrative tasks at $48.04 per hour.

 The shared capital cost for optical gas imaging system is $ 491 for production and gathering and boosting, $85,000 for processing, and $1,063 for transmission for a FLIR Model GF320 optical gas imaging system

.

 The capital cost also includes $14,500 for a data collection system for maintaining the inventory and monitoring records for the components at a facilit y.

 Recovery credits were calculated assuming the methane reduction has a value of $4 .00 per 1000 standard cubic feet.
A summary of the capital and annual costs and the cost effectiveness for each of the model plants in the oil and gas sectors using the alternative work practice monitoring is provided in Table 8

- 1 9

. A component cost effectiveness analysis for the alternative work practice was not performed, because the optical gas imaging system is not conducive to component monitoring, but is intended fo r facility

- wide monitoring.

8.4. 4 .4 Secondary Impacts
The implementation of a LDAR program reduces pollutant emissions from equipment leaks. No secondary gaseous pollutant emissions or wastewater are generated during the monitoring and repair of equipment leaks. Therefore, there are no secondary impacts expected from the implementation of a LDAR program.

8 .5 Regulatory Options
The LDAR pollution prevention approach is believed to be the best method for reducing pollutant emissions from equipment leaks. Ther efore, the following regulatory options were considered for reducing equipment leaks from well pads, gathering and boosting stations, processing facilities, and transmission and storage facilities:

 Regulatory Option 1: Require the implementation of a subpart VVa LDAR program;

 Regulatory Option 2: Require the implementation of a component subpart VVa LDAR program;

 Regulatory Option 3: Require the implementation of the alternative work practice in §6 0.18 of 40 CFR Part 60;8

- 36 Table 8

- 1 9

. Summary of the Model Plant C ost Effectiveness for Monthly Gas Imaging Monitoring

Model Plant Annual Emission Reductions (tons/year) Capital Cost ($) Annual Cost

($/year) Cost Effectiveness ( $/ton)
VOC HAP Methane without savings with

savings VOC HAP Methane
Well Pads
1 N/A N/A N/A $15,390 $21,373 N/A N/A N/A N/A
2 N/A N/A N/A $64,820 $37,049 N/A N/A N/A N/A
3 N/A N/A N/A $537,313 $189,174 N/A N/A N/A N/A Gathering and Boosting Stations
1 N/A N/A N/A $ 149,051 $ 59,790 N/A N/A N/A N/A
2 N/A N/A N/A $ 240,491 $ 86,135 N/A N/A N/A N/A
3 N/A N/A N/A $ 329,687 $ 11,940 N/A N/A N/A N/A Processing Plants
1 N/A N/A N/A $92,522 $76,581 N/A N/A N/A N/A Transmission/Storage Facilities
1 N/A N/A N/A $ 20,817 $ 45,080 N/A N/A N/A N/A

Note: T his option only provides the number and magnitude of the leaks

. Therefore, the emission reduction from this program cannot be quantified and the cost effectiveness values calculated.8

- 37

 Regulatory Option 4: Require the implementation of a modified alternative work practice in §60.18 of 40 CFR Part 60 that removes the requirement for annual monitoring using a Method 21 device.
The following sections discuss these regulatory options.

8.5.1 Evaluation of Regulatory Options for Equipment Leaks

8.5.1.1 Well pads
The first regulatory option of a subpart VVa LDAR program was evaluated for well pads, which include the wells, processing equipment (separators, dehydrators, acid gas removal), as wel l as any heaters and piping. The equipment does not include any of the compressors which will be regulated separately. For well pads the VOC cost effectiveness for the model plants ranged from $267,386 per ton of VOC for a single well head facility to $6,9 34 ton of VOC for a well pad servicing 48 wells. Because of the high VOC cost effectiveness, Regulatory Option 1 was rejected for well pads.
The second regulatory option that was evaluated for well pads was Regulatory Option 2, which would require the imp lementation of a component subpart VVa LDAR program

. The VOC cost effectiveness of this option ranged from $15,063 for valves to $211,992 for open

- ended lines

. These costs were determined to be unreasonable and therefore this regulatory option was rejected.
The third regulatory option requires the implementation of a monthly LDAR program using an Optical gas imaging system with annual monitoring using a Method 21 device

. The VOC cost effectiveness of this option ranged from $5,364 per ton of VOC for Model Plant 3to $ 2 4 5 , 024 per ton of VOC for Model Plant 1

. T his regulatory option was determined to be not cost effective and was rejected.
The fourth regulatory option would require the implementation of a monthly LDAR program using an optical imaging in strument

. The emission reductions from this option could not be quantified; therefore this regulatory option was rejected.

8.5.1. 2 Gathering and Boosting Stations
The first regulatory option was evaluated for gathering and boosting stations which include t he processing equipment (separators, dehydrators, acid gas removal), as well as any heaters and piping

. The equipment does not include any of the compressors which will be regulated separately

. The VOC cost effectiveness for the gathering and boosting mode l plants ranged from $1 0 , 327 per ton of VOC for8

- 38

Model Plant 1 to $ 8 , 174 per ton of VOC for Model Plant 3

. Regulatory Option 1 was rejected due to the high VOC cost effectiveness

. The second regulatory option that was evaluated for gathering and boosting st ations was Regulatory Option 2

. The VOC cost effectiveness of this option ranged from $ 6,079 for valves to $ 7 7 , 310 per ton of VOC for open

- ended lines

. These costs were determined to be unreasonable and therefore this regulatory option was also rejected.

T he third regulatory option requires the implementation of a monthly LDAR program using an Optical gas imaging system with annual monitoring using a Method 21 device

. The VOC cost effectiveness of this option was calculated to be $ 1 0 , 724 per ton of VOC for Model Plant 1 and $ 8 , 685 per ton of VOC for Model Plant 3

. T his regulatory option was determined to be not cost effective and was rejected.
The fourth regulatory option would require the implementation of a monthly LDAR program using an optical imaging instrument

. The emission reductions from this option could not be quantified; therefore this regulatory option was rejected.

8.5.1. 3 Processing Plants

The VOC cost effectiveness of the first regulatory option was calculated to be $3,352 pe r ton of VOC

. Th i s cost effectivenes s w as determined to be reasonable and therefore this regulatory option was

a ccepted

. The second option was evaluated for processing plants and the VOC cost effectiveness ranged from $0 for open

- ended lined and pressure r elief devices to $4,360 for connectors

. Because the emission benefits and the cost effectiveness of Regulatory Option 1 were accepted, this option was not accepted.

The third regulatory option requires the implementation of a monthly LDAR program using an Optical gas imaging system with annual monitoring using a Method 21 device

. The VOC cost effectiveness of this option was calculated to be $ 6,462 per ton of VOC and was determined to be not cost effective

. Therefore , this regulatory option was rejected.

Th e fourth regulatory option would require the implementation of a monthly LDAR program using an optical imaging instrument

. The emission reductions from this option could not be quantified; therefore this regulatory option was rejected.

8.5.1. 4 Transmission and Storage Facilities8

- 39

The first regulatory option was evaluated for transmission and storage facilities which include separators and dehydrators, as well as any heaters and piping

. The equipment does not include any of the compressors which will be regulated separately

. This sector moves processed gas from the processing facilities to the city gates

. The VOC cost effectiveness for Regulatory Option 1 was $ 19,769 per ton of VOC

. The high VOC cost effectiveness is due to the inherent low VOC concentrati on in the processed natural gas, therefore the VOC reductions from this sector are low in comparison to the other sectors

. Regulatory Option 1 was rejected due to the high VOC cost effectiveness

. The second option was evaluated for transmission facilities and the VOC cost effectiveness ranged from $24,762 for open

- ended lined to $243,525 for connectors

. This option was not accepted because of the high cost effectiveness.

The third regulatory option that was evaluated for transmission and storage facilities was Regulatory Option 3

. The VOC cost effectiveness of this option was calculated to be $ 19 , 723 per ton of VOC

. Again, because of the low VOC content of the processed gas, the regulatory option has a low VOC reduction

. Th is cost w as determined to be unrea sonable and therefore this regulatory option was also rejected.
The fourth regulatory option would require the implementation of a monthly LDAR program using an optical imaging instrument

. The emission reductions from this option could not be quantified; t herefore this regulatory option was rejected.

8 .5. 2 Nationwide Impacts of Regulatory Options
Regulatory Option 1 was selected as an option for setting standards for equipment leaks at processing plants

. This option would require the implementation of an LD AR program using the subpart VVa requirements

. For production facilities, 29 facilities per year are expected to be affected sources by the NSPS regulation annually

. Table 8

- 20 provides a summary of the expected emission reductions from the implementation of this option

.8

- 40 Table 8

- 20 . Nationw ide Emission and Cost Analysis of Regulatory Options

Category Estimated

Nu mber of Sources subject to NSPS Facility

Capital Cost ($) Natio nwide Emission

Reductions (tpy) VOC Cost Effectiveness ($/ton) Methane Cost

Effectiveness ($/ton) Total Nationwide Costs

(million $/year)

VOC Methane HAP without savings with

savings without

savings with

savings Capital

Cost Annual without savings Annual

with savings Regulatory Option 2 (Subpart VVa LDAR Program) Processing Plants 29 $7,522 392 1,407 14. 7 $3,3 52 $2,5 17 $9 31 $69 9 0.218 1.31 0.98 48

- 41

8 .6 References

1 Memorandum 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.

2 Memorandum from Kristen Parrish, RTI and David Randall, RTI to Karen Rackley, U.S. Environme ntal Protection Agency.Final Impacts for Regulatory Options for Equipment Leaks of VOC on SOCMI. October 30, 2007.

3 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.

4 U.S. Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Si nks1990

- 2008. Washington, DC.

5 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.

6 Radian Internatio nal LLC. Methane Emissions from the Natural Gas Industry, Vol. 3: General Methodology. Prepared for the Gas Research Institute and Environmental Protection Agency.EPA

- 600/R

- 96

- 080c. June 1996.

7 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

8 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

9 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 6: Vented and Combustion Source Summary Emissions. Prepared for the Gas Research Institute and Environmental Protection Agency.EPA

- 600/R

- 96

- 080f. June 1996.

10 Radian International LLC, Methane Emissions from the U.S. Petroleum Industry , draft report for the U.S. Environmental Protection Agency, June 14, 1996.

11 ICF Consulting. Estimat es of Methane Emissions from the U.S. Oil Industry.Prepared for the U.S. Environmental Protection Agency. 1999.

12 ENVIRON International Corporation. Oil and Gas Emission Inventories for the Western States.Prepared for Western Governors’ Association. Dece mber 27, 2005.8

- 42

13 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

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

15 Armendariz, Al. Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost

- Effective Improvements. Prepared for Environmental Defense Fund. J anuary 2009.

16 Eastern Research Group, Inc. Emissions from Oil and Gas Production Facilities. Prepared for the Texas Commission on Environmental Quality. August 31, 2007.

17 U.S. Energy Information Administration. Annual U.S. Natural Gas Wellhead Price.E nergy Information Administration.Natural Gas Navigator. Retrieved online on 12 Dec 2010 at <http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm>

18 Eastern Research Group, Inc. Preferred and Alternative Methods for Estimating Air Emissions from Oil and Gas F ield Production and Processing Operation. Prepared for the U.S. Environmental Protection Agency. September 1999.APPENDIX A

E&P TANKS ANALYSIS FOR STORAGE VESSELSTank ID Sample Tank No. 1 Sample Tank No. 2 Sample Tank No. 3 Sample Tank No. 4 Sample Tank No. 5 Sample Tank No. 6 Sample Tank No. 7 Sample Tank No. 8

E&P Tank Number Tank No. 58 Tank No. 59 Tank No. 60 Tank No. 61 Tank No. 62 Tank No. 63 Tank No. 64 Tank No. 65 Total Emissions (tpy) 289.778 230.196 129.419 129.853 201.547 738.511 294.500 142.371 VOC Emissions (tpy) 43.734 111.414 101.853 63.343 154.313 578.379 205.794 89.728 Methane Emissions (tpy) 0.197 56.006 10.064 50.910 8.343 47.831 26.305 24.276 HAP Emissions (tpy) 4.236 13.100 5.050 2.730 3.500 37.840 4.480 2.680 Benzene 0.828 6.343 0.501 0.285 0.051 7.568 0.116 0.219 Toluene 1.194 3.539 0.648 0.243 0.067 5.950 0.085 0.301 E-Benzene 0.041 0.083 0.040 0.008 0.002 0.086 0.006 0.020 Xylenes 0.165 0.327 0.233 0.066 0.046 0.679 0.018 0.152 n-C6 2.008 2.809 3.623 2.132 3.333 23.553 4.252 1.989 224Trimethylp 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 Separator Pressure (psig) 66 66 13 64 28 95 29 44 Separator Temperature (F) 83 90 110 74 78 118 60 71 Ambient Pressure (psia) 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 Ambient Temperature (F) 83 90 110 74 78 118 60 71 C10+ SG 0.848 0.865 0.879 0.866 0.864 0.862 0.841 0.849 C10+ MW 234 237 294 301 281 312 224 349 API Gravity 40.0 40.0 40.0 40.0 42.0 42.0 44.0 44.0 Production Rate (bbl/day) 500 500 500 500 500 500 500 500 Reid Vapor Pressure (psia) 3.00 4.10 4.80 3.90 4.20 8.10 5.70 7.00 GOR (scf/bbl) 25.96 30.32 12.30 19.58 19.68 68.74 32.46 16.92 Heating Value of Vapor (Btu/scf) 398.80 1689.70 2486.42 1567.19 2261.27 2529.29 2162.56 2003.83 LP Oil Component mol % H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO2 5.0200 0.2700 0.0000 0.0800 0.0400 0.0000 0.0100 0.0200 N2 0.0000 0.0100 0.0000 0.0200 0.3100 0.0200 0.0200 0.0100 C1 0.0100 2.2600 0.4700 2.6500 0.4000 2.2500 1.1300 1.2900 C2 0.0400 1.2000 0.4800 0.3900 0.6500 3.1100 1.4100 1.0300 C3 0.2000 1.3200 1.5800 0.9200 1.7500 4.1100 3.2900 2.3000 i-C4 0.2800 0.7100 0.6200 0.9800 0.9200 1.3300 0.4500 1.1200 n-C4 0.4800 1.0800 2.6100 1.4700 2.4500 3.8100 4.0200 3.2200 i-C5 0.7600 1.2000 1.8100 2.0500 2.3900 2.5400 0.7000 2.3600 n-C5 0.7400 1.1300 2.9300 2.1600 2.9500 3.5100 4.0700 2.9600 C6 1.5100 2.0000 3.8800 3.4500 2.7600 3.0900 0.9600 3.0600 C7 4.6600 6.7600 10.7300 7.9400 10.8800 8.0100 5.5900 9.5000 C8 6.6100 9.4200 12.5300 9.6900 11.6400 7.6800 5.5200 11.5900 C9 4.8700 6.5600 6.9400 6.5600 6.1800 4.4400 4.2700 6.3200 C10+ 70.1100 49.2600 47.3100 56.3900 52.0200 47.6400 63.0500 47.7200 Benzene 0.5700 4.9100 0.5800 0.4300 0.0700 1.3400 0.1600 0.3600 Toluene 2.1400 7.7900 1.9900 1.1000 0.2700 2.6800 0.3700 1.4900 E-Benzene 0.1700 0.4600 0.2900 0.1000 0.0200 0.0900 0.0700 0.2600 Xylenes 0.7600 2.0500 1.9000 0.9000 0.5500 0.8000 0.2500 2.2900 n-C6 1.0700 1.6100 3.3500 2.7200 3.7500 3.5500 4.6600 3.1000 224Trimethylp 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 9 Sample Tank No. 10 Sample Tank No. 11 Sample Tank No. 12 Sample Tank No. 13 Sample Tank No. 14 Sample Tank No. 15 Tank No. 66 Tank No. 67 Tank No. 68 Tank No. 69 Tank No. 70 Tank No. 71 Tank No. 72 357.688 134.789 314.446 505.131 306.443 256.029 1061.274 243.348 79.118 224.158 437.555 252.987 204.571 987.647 56.846 37.876 18.892 21.472 15.159 21.237 32.940 5.590 5.680 7.030 13.450 15.330 6.500 56.780 0.244 1.308 0.242 0.119 1.048 0.464 5.791 0.440 1.184 0.385 0.146 1.488 0.927 6.793 0.039 0.029 0.043 0.019 0.062 0.051 0.303 0.208 0.488 0.167 0.162 0.734 0.590 4.255 4.661 2.671 6.191 13.008 12.001 4.468 39.634 0.000 0.000 0.000 0.000 0.000 0.000 0.000 60 41 20 23 24 52 45 60 72 68 85 114 108 140 14.7 14.7 14.7 14.7 14.7 14.7 14.7 60 72 68 85 114 108 140 0.878 0.854 0.926 0.848 0.87 0.886 0.893 270 270 290 275 274 269 277 44.0 45.0 45.0 46.0 46.0 47.0 47.0 500 500 500 500 500 500 500 10.10 5.20 8.10 4.70 5.00 5.30 6.00 41.30 17.66 30.80 43.26 26.30 24.28 78.80 2060.54 1812.87 2234.66 2651.81 2611.90 2491.55 3120.85

0.0000 0.0000 0.0000 0.0500 0.0700 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0500 0.0400 0.3100 0.2400 0.1700 0.0000 0.0400 0.0000 0.0100 0.0200 0.0100 0.0000 0.0000 0.0000 2.3400 1.8400 0.6900 0.9400 0.6200 0.9700 1.2100 1.5600 0.6100 0.9400 0.6600 0.5200 0.7700 0.7600 3.8500 1.2700 2.7300 2.1500 1.6800 2.0200 2.9200 1.3600 0.8900 1.7300 1.1100 0.9900 1.5500 4.1500 3.9600 1.5600 3.9300 4.5400 3.1200 2.1400 3.0600 3.1300 1.8000 3.8800 3.0600 2.4500 3.3400 3.9300 4.0300 1.8800 4.1000 4.9800 3.4200 2.8800 3.0900 3.6100 3.4300 5.1500 4.1100 4.4300 3.2600 4.9100 7.7900 10.7400 12.0700 10.2100 8.8900 9.0800 13.0800 13.7700 12.6900 18.2000 10.6800 18.5800 11.7900 14.6200 4.8300 7.8700 8.8800 5.4300 8.7200 5.8500 7.6300 42.2300 43.0100 27.3600 45.2800 36.2600 49.3100 31.1400 0.2400 1.5600 0.3000 0.0600 0.5300 0.3000 0.6900 1.3400 3.8100 1.4700 0.2100 1.9700 1.6000 1.9400 0.3200 0.2200 0.4400 0.0700 0.1900 0.2100 0.1900 1.9700 4.1900 1.9600 0.6700 2.5500 2.7300 2.9800 3.6200 2.5800 5.8400 5.5400 4.8400 2.2000 3.6600 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 16 Sample Tank No. 17 Sample Tank No. 18 Sample Tank No. 19 Sample Tank No. 20 Sample Tank No. 21 Tank No. 73 Tank No. 74 Tank No. 75 Tank No. 76 Tank No. 77 Tank No. 78 464.597 214.658 1331.488 3972.618 540.533 1228.897 383.349 135.482 1146.617 2331.105 399.555 940.078 18.132 32.283 31.967 755.826 38.624 105.184 10.980 7.530 77.780 82.380 7.580 13.230 0.222 1.269 7.661 12.470 2.447 0.543 0.208 0.708 3.775 23.584 1.643 0.466 0.058 0.019 0.113 0.056 0.051 0.006 0.193 0.411 0.929 0.635 0.256 0.052 10.296 5.124 65.304 45.632 3.186 12.160 0.000 0.000 0.000 0.000 0.000 0.000 40 31 50 700 20 98 76 76 125 100 48 40 14.7 14.7 14.7 14.7 14.7 14.7 76 76 125 100 48 40 0.885 0.839 0.842 0.878 0.877 0.929 318 296 287 178 179 324 47.0 49.0 49.0 50.0 50.0 51.0 500 500 500 500 500 500 10.60 5.00 8.90 7.40 9.40 11.20 41.32 24.48 106.60 491.90 56.44 128.16 2421.27 2045.68 2822.40 1916.15 2275.04 2279.83

0.0000 0.0000 1.2800 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0400 0.0800 0.0300 0.4200 0.0100 0.0100 0.8400 0.0100 0.0000 0.0700 0.0100 0.0400 0.7800 1.4000 1.2700 15.3300 1.1400 3.2200 0.7500 0.9700 2.0800 8.9600 1.6000 2.9500 3.5300 1.3500 4.5700 8.2100 4.0100 6.4800 2.0700 1.0500 1.8900 2.3100 2.3400 2.2000 6.8800 2.4200 6.4800 4.1900 4.7300 8.5300 5.0000 2.7100 3.8800 2.4300 4.1700 4.6800 7.4800 3.2900 7.0400 2.3500 2.9700 7.4700 4.1000 4.6900 3.0500 3.1100 4.3800 5.7300 11.3200 11.3500 6.8200 8.4700 8.8100 15.8300 11.7900 12.4100 7.7800 8.8400 12.3800 12.6400 6.1100 9.3100 7.2300 3.7100 5.4900 4.0800 32.0700 36.0900 37.9300 23.5600 32.1400 18.1600 0.1400 1.4000 0.8300 0.8200 2.8900 0.3400 0.3800 2.3200 1.0200 4.6700 6.4200 1.0200 0.2700 0.1600 0.0700 0.0300 0.5700 0.0400 1.0300 4.0200 0.6500 0.3900 3.3000 0.4000 5.4200 4.9700 6.1000 2.1300 2.6400 6.1800 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 22 Sample Tank No. 23 Sample Tank No. 24 Sample Tank No. 25 Sample Tank No. 26 Sample Tank No. 27 Tank No. 79 Tank No. 80 Tank No. 81 Tank No. 82 Tank No. 83 Tank No. 84 362.298 790.092 557.188 5007.636 175.911 714.052 175.304 665.349 483.599 3386.300 77.584 639.895 109.676 24.115 10.288 842.206 54.660 18.553 7.150 28.770 14.580 101.610 4.770 30.190 0.353 3.892 1.930 9.782 0.929 4.165 0.102 6.465 1.651 12.547 0.909 2.542 0.120 0.119 0.055 0.040 0.050 0.192 0.437 2.017 0.631 0.716 0.221 1.424 6.133 16.273 10.317 78.528 2.665 21.871 0.000 0.000 0.000 0.000 0.000 0.000 115 30 15 770 39 38 73 100 86 100 66 95 14.7 14.7 14.7 14.7 14.7 14.7 73 100 86 100 66 95 0.873 0.901 0.878 0.858 0.854 0.823 200 220 254 195 175 375 54.0 54.0 54.0 55.0 57.0 57.0 500 500 500 500 500 500 5.30 9.40 10.30 7.80 5.70 9.60 51.34 68.32 47.12 578.20 25.46 57.38 1678.80 2676.21 2764.90 2043.18 1632.00 2897.16

0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0900 0.1100 0.0200 0.5500 0.0700 0.0400 0.0300 0.0200 0.0100 0.0300 0.0000 0.0000 3.5600 0.7100 0.3300 16.1500 1.7200 0.7000 1.4300 1.5400 1.0900 7.1400 0.9000 1.0900 1.8700 4.5900 3.8300 9.6600 1.3800 3.5600 0.6800 2.3400 3.7000 3.8100 1.0000 2.9000 2.0000 4.4400 4.8700 5.9600 1.4900 6.2100 1.6600 3.9000 4.4800 3.5300 1.4600 6.0400 2.0600 3.8000 3.9800 3.7200 1.5300 5.8400 2.4100 5.0900 6.0500 3.8400 4.0600 7.3200 15.0800 12.9700 15.6400 8.7600 14.5700 13.0000 25.1900 19.0700 17.5800 8.9200 23.7200 12.2200 12.4900 6.9500 6.1000 3.1000 13.7700 7.9600 24.3900 18.9200 21.1300 17.9300 20.9800 20.0200 0.2400 1.2000 1.0500 0.5800 1.4900 1.2200 0.2100 5.5400 2.6000 2.3000 4.5300 2.0500 0.6600 0.2500 0.2200 0.0200 0.6700 0.3800 2.7600 4.8300 2.8900 0.4200 3.4200 3.2200 3.1900 3.7300 4.4300 3.5800 3.2400 6.2300 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 28 Sample Tank No. 29 Sample Tank No. 30 Sample Tank No. 31 Sample Tank No. 32 Sample Tank No. 33 Tank No. 85 Tank No. 86 Tank No. 87 Tank No. 88 Tank No. 89 Tank No. 90 801.228 983.881 4326.573 3074.670 2951.879 616.490 757.176 750.313 2406.579 1892.668 1439.584 332.126 5.307 49.123 1088.727 746.499 999.175 120.918 29.510 14.080 58.180 47.230 44.040 9.140 3.415 1.119 4.653 5.891 1.409 0.576 5.329 1.453 5.785 6.575 2.934 1.658 0.192 0.049 0.186 0.022 0.159 0.079 1.786 0.263 0.989 0.316 1.136 0.806 18.788 11.194 46.561 34.427 38.406 6.016 0.000 0.000 0.000 0.000 0.000 0.000 65 54 870 600 780 60 80 60 78 70 70 56 14.7 14.7 14.7 14.7 14.7 14.7 80 60 78 70 70 60 0.899 0.868 0.868 0.847 0.905 0.905 166 268 268 176 174 174 57.0 57.0 57.0 57.0 58.0 58.0 500 500 500 500 500 500 4.80 13.10 13.10 7.50 8.00 8.00 61.26 97.00 578.20 396.24 436.98 79.54 3046.83 2390.47 1789.23 1831.51 1633.60 1851.14

0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0100 0.0800 0.4200 0.5800 0.2700 0.0800 0.0000 0.0000 0.0800 0.0200 0.0200 0.0100 0.1500 1.4800 21.2000 16.0200 20.3000 3.3900 0.5700 2.9100 8.2900 4.1200 5.1800 2.4300 2.4100 6.9600 8.5400 6.9000 5.6800 3.8400 1.7300 2.6300 2.3000 2.7500 1.4200 1.3000 3.5500 7.2100 5.8400 4.9100 4.1400 3.2000 4.1400 4.6400 3.3500 3.6000 2.5400 2.4100 3.8600 5.7100 4.0400 3.9000 3.1000 2.5600 6.5100 5.0100 3.4200 3.9500 3.7700 3.7700 18.7100 13.5500 9.1200 10.3800 11.2200 13.2600 19.4300 15.0600 10.0900 11.3000 14.7500 22.4400 6.8400 6.2300 4.1700 4.2100 7.0600 11.1300 15.5200 18.8400 12.5900 19.2800 13.5400 16.0600 1.1800 0.5900 0.4000 0.8200 0.1800 0.4100 5.2100 2.5000 1.6800 3.0600 1.2600 3.8600 0.4600 0.2400 0.1600 0.0300 0.2000 0.5200 4.8600 1.4900 1.0000 0.5000 1.6700 6.1500 4.8600 4.8700 3.3100 3.6700 3.7000 3.1800 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 34 Sample Tank No. 35 Sample Tank No. 36 Sample Tank No. 37 Sample Tank No. 38 Sample Tank No. 39 Tank No. 91 Tank No. 92 Tank No. 93 Tank No. 94 Tank No. 95 Tank No. 96 2575.122 2774.089 653.459 3495.242 363.650 4744.399 1494.749 2092.925 394.781 2876.860 223.772 3658.384 581.208 346.071 121.446 169.818 84.912 381.967 65.980 48.710 14.210 93.030 10.760 89.970 9.303 2.750 0.871 10.232 0.500 11.564 14.114 2.311 2.688 11.558 0.279 11.735 0.019 0.128 0.136 0.034 0.060 0.033 0.409 0.872 1.400 0.580 0.256 0.472 42.130 42.650 9.111 70.629 9.661 66.162 0.000 0.000 0.000 0.000 0.000 0.000 500 300 110 750 85 730 84 80 72 90 85 84 14.7 14.7 14.7 14.7 14.7 14.7 84 80 72 90 85 84 0.909 0.882 0.901 0.898 0.9 0.898 204 296 162 215 202 225 58.0 58.0 59.0 60.0 61.0 61.0 500 500 500 500 500 500 9.10 10.60 10.00 9.40 7.00 9.80 323.88 287.10 79.90 320.48 45.04 475.20 1892.64 2289.04 1946.32 2541.49 1921.87 2340.56

0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2300 0.0300 0.0800 0.3400 0.0400 0.4100 0.0600 0.0900 0.0100 0.0200 0.0200 0.0300 12.9800 8.4300 3.3900 3.7500 2.6100 7.3900 5.7800 4.2300 2.4300 4.7700 1.1600 6.6400 4.6400 5.9100 3.8400 9.2600 2.2100 10.9400 2.0900 5.1700 1.3000 4.8100 0.9300 4.5800 4.1800 6.2200 3.2000 7.0200 2.4900 8.3400 4.9600 8.9100 2.4100 5.5900 2.1300 5.5000 4.0700 4.9700 2.5600 6.1200 2.9200 5.8200 6.0700 9.1100 3.7700 6.1300 3.5400 5.3200 13.1100 11.3400 13.2600 12.8200 19.5300 11.2900 11.9500 10.3900 22.4400 12.5200 27.1600 11.1800 4.8600 5.9600 11.1300 4.0100 14.7000 3.1900 14.1100 11.7500 16.0600 11.4200 13.8800 8.8000 1.1400 0.3700 0.4100 1.1000 0.2900 1.1400 5.4100 0.9800 3.8600 3.7900 0.4700 3.7600 0.0200 0.1500 0.5200 0.0300 0.2600 0.0300 0.5000 1.1900 6.1500 0.5900 1.2600 0.5000 3.8400 4.8000 3.1800 5.9100 4.4000 5.1400 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 40 Sample Tank No. 41 Sample Tank No. 42 Sample Tank No. 43 Sample Tank No. 44 Sample Tank No. 45 Tank No. 97 Tank No. 98 Tank No. 99 Tank No. 100 Tank No. 101 Tank No. 102 907.495 277.197 3410.034 2122.607 8152.118 6780.555 734.651 158.333 2732.261 1066.705 5678.554 4276.160 49.578 75.426 159.904 736.341 1206.981 1045.765 24.160 8.820 67.500 64.680 81.710 48.890 1.573 0.204 9.290 9.500 10.844 5.934 3.102 0.854 9.192 15.007 8.516 1.416 0.094 0.042 0.016 0.161 0.012 0.222 1.079 0.375 0.371 1.585 0.288 1.359 18.314 7.344 48.628 38.425 62.050 39.961 0.000 0.000 0.000 0.000 0.000 0.000 57 72 730 580 730 807 82 80 80 77 80 96 14.7 14.7 14.7 14.7 14.7 14.7 82 80 80 77 80 96 0.884 0.869 0.883 0.85 0.895 0.811 240 190 226 190 197 173 62.0 63.0 63.0 64.0 64.0 66.0 500 500 500 500 500 500 10.40 7.00 11.90 6.40 11.00 11.80 84.20 36.56 321.62 309.64 924.96 804.54 2521.70 1805.12 2477.18 1622.20 2083.02 2013.21

0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0800 0.0400 0.3200 0.0700 0.5600 0.2200 0.0100 0.0300 0.0200 0.0700 0.0300 0.0800 1.4000 2.3500 3.4800 16.3500 16.9100 16.2600 1.7700 1.0000 5.5300 3.6400 8.6200 11.7100 4.8200 2.0700 10.1700 3.5600 12.0400 11.6100 2.8200 0.7100 4.9900 1.6900 5.2700 4.3900 5.9700 2.2600 8.1400 2.9800 9.0700 7.5600 4.3100 1.7000 5.8700 2.6800 5.6500 4.5200 4.1900 2.7400 6.1600 2.7900 5.8200 3.9400 6.5100 3.4900 5.7200 3.8200 5.1000 3.3600 17.7500 17.7300 12.3800 18.1400 8.0600 5.9200 18.6400 27.9100 12.3100 19.4700 7.5500 11.6900 7.4400 16.1500 3.7900 4.5900 2.2200 5.9200 11.6100 12.2800 9.9100 6.7300 5.6700 8.9300 0.5600 0.1600 1.2800 1.2200 0.8500 0.3700 3.2800 1.9800 4.0500 6.0700 2.3800 0.3000 0.2600 0.2500 0.0200 0.1800 0.0100 0.1400 3.4100 2.5800 0.5300 2.0600 0.2900 1.0100 5.1700 4.5700 5.3300 3.8900 3.9000 2.0700 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 46 Sample Tank No. 47 Sample Tank No. 48 Sample Tank No. 49 Sample Tank No. 50 Sample Tank No. 51 Tank No. 103 Tank No. 1 Tank No. 2 Tank No. 3 Tank No. 4 Tank No. 5 927.902 95.816 112.738 74.503 155.244 93.073 623.038 6.175 61.936 28.446 61.470 51.471 167.129 0.115 1.927 0.309 46.064 0.440 20.320 0.460 2.960 0.990 1.760 3.190 1.625 0.006 0.076 0.012 0.010 0.218 1.876 0.013 0.060 0.031 0.037 0.074 0.062 0.007 0.019 0.002 0.025 0.006 0.696 0.018 0.105 0.041 0.069 0.048 16.059 0.421 2.704 0.904 1.616 2.845 0.000 0.000 0.000 0.000 0.000 0.000 170 45 22 20 53 15 75 106 155 160 101 120 14.7 14.7 14.7 14.7 14.7 14.7 75 106 155 160 101 120 0.801 0.972 0.972 0.952 0.961 0.984 196 425 436 458 394 551 68.0 15.0 17.0 18.0 19.0 19.0 500 500 500 500 500 500 12.50 0.80 2.00 0.60 2.30 4.80 106.60 8.88 9.60 6.44 17.78 7.52 2081.33 181.43 1738.61 1076.97 1365.68 1718.17

0.0000 0.1100 0.0000 0.0400 0.5100 0.1400 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0100 2.8500 1.3000 1.5400 1.1900 1.5000 0.0100 0.0000 0.0000 0.0300 0.0100 0.0000 4.9300 0.0100 0.1500 0.0300 1.5300 0.0400 2.5800 0.0100 0.4000 0.0400 0.5300 0.2400 3.4200 0.0200 0.7800 0.2200 0.8100 0.8500 3.4300 0.0500 0.5600 0.1600 0.5000 0.6500 3.7300 0.1800 1.2600 0.4700 1.2000 1.6500 5.5500 0.3200 0.8700 0.4300 1.1500 2.1900 3.6500 0.4500 1.2400 0.6500 1.3400 3.1500 8.0700 0.6000 1.9800 0.6100 1.7500 4.7300 14.6500 1.7200 3.4500 1.5800 3.6200 6.2500 13.2600 2.1800 4.2600 2.0700 3.5300 10.2800 7.8000 1.8400 3.6600 2.2800 3.5300 5.9300 19.6300 88.7100 78.1500 88.9700 76.8100 57.9100 0.5400 0.0100 0.0500 0.0100 0.0100 0.3000 1.9200 0.0600 0.0900 0.0600 0.1000 0.2600 0.1700 0.0800 0.0600 0.0100 0.1600 0.0500 2.2200 0.2300 0.3700 0.1800 0.5100 0.4300 4.4300 0.5700 1.3700 0.6200 1.2100 3.4500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 52 Sample Tank No. 53 Sample Tank No. 54 Sample Tank No. 55 Sample Tank No. 56 Sample Tank No. 57 Tank No. 6 Tank No. 7 Tank No. 8 Tank No. 9 Tank No. 10 Tank No. 11 24.484 26.091 29.739 114.630 42.075 3.087 17.629 11.288 74.707 8.263 15.587 2.836 5.908 25.400 27.176 0.190 0.510 0.330 2.120 0.090 0.003 0.007 0.013 0.039 0.028 0.006 0.014 0.008 0.071 0.010 0.000 0.001 0.003 0.007 0.000 0.005 0.012 0.007 0.090 0.001 0.175 0.474 0.298 1.919 0.052 0.000 0.000 0.000 0.000 0.000 23 17 18 54 35 79 106 75 125 76 14.7 14.7 14.7 14.7 14.7 79 106 75 125 76 0.947 0.967 0.963 0.943 0.923 368 383 401 363 278 20.0 20.0 20.0 21.0 23.0 500 500 500 500 500 1.20 3.30 3.80 1.10 1.80 4.98 2.82 3.94 13.90 8.52 1067.32 2208.23 1236.41 1980.20 1192.63

0.0100 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0700 0.0000 0.2500 0.0000 0.0600 0.0900 0.0000 0.2100 0.0100 0.0100 1.2500 0.1900 0.5300 1.8000 1.7700 0.2000 0.2300 0.3300 0.5400 0.2900 0.0800 0.7500 0.7500 0.5200 0.3700 0.0900 0.4900 0.4900 0.2800 0.2300 0.1800 1.5700 1.5000 0.9200 0.3100 0.4000 1.5300 1.3500 0.9800 0.4900 0.4500 1.9100 1.7700 0.9700 0.2400 1.0500 2.7500 2.3700 1.6800 0.2500 2.3300 3.9000 4.3000 3.0100 0.5900 2.9800 6.8100 5.5200 3.7300 0.5000 2.6000 4.0100 3.5700 3.5400 0.2500 87.0300 73.0300 74.2800 80.2500 94.2100 0.0200 0.0400 0.1000 0.0300 0.1100 0.1100 0.2200 0.1900 0.1400 0.1200 0.0200 0.0500 0.1900 0.0300 0.0100 0.2700 0.5100 0.4700 0.4500 0.0500 0.7700 2.0100 1.8300 1.1200 0.1400 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 0.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 58 Sample Tank No. 59 Sample Tank No. 60 Sample Tank No. 61 Sample Tank No. 62 Sample Tank No. 63 Tank No. 12 Tank No. 13 Tank No. 14 Tank No. 15 Tank No. 16 Tank No. 17 134.719 26.214 195.573 142.068 191.224 35.095 63.729 5.207 109.615 69.135 105.838 25.578 16.689 12.924 7.759 5.438 4.313 3.029 1.170 0.430 2.810 1.760 2.110 0.750 0.020 0.008 0.033 0.024 0.041 0.011 0.014 0.032 0.032 0.053 0.079 0.022 0.007 0.002 0.023 0.003 0.003 0.003 0.027 0.019 0.064 0.041 0.016 0.011 1.104 0.371 2.659 1.640 1.969 0.701 0.000 0.000 0.000 0.000 0.000 0.000 30 20 20 22 20 19 66 122 88 86 68 133 14.7 14.7 14.7 14.7 14.7 14.7 66 122 88 86 68 133 0.946 0.926 0.945 0.944 0.964 0.928 382 336 381 404 444 327 23.0 24.0 24.0 24.0 24.0 25.0 500 500 500 500 500 500 4.00 0.60 3.90 4.60 4.80 4.10 15.42 4.60 19.12 13.74 17.84 3.48 1553.86 1059.39 1747.39 1543.44 1703.42 2314.31

0.4400 0.0000 0.5200 0.4500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.6400 0.1200 0.9600 1.1500 1.4200 0.0500 0.0100 0.1000 0.1200 0.0200 0.0200 0.0000 1.0700 0.9400 0.4900 0.3600 0.2700 0.2500 0.5400 0.0500 0.6500 0.5000 0.6200 0.4900 1.4100 0.0700 1.7300 1.5900 1.9400 1.1600 0.7000 0.0600 0.7400 0.7600 1.1000 0.6000 1.9400 0.1000 2.4600 2.4000 3.0100 1.5900 1.8900 0.2400 1.7900 1.7300 2.1900 1.4300 2.3600 0.2300 2.3100 2.1400 3.2100 1.4400 2.7100 0.9100 2.6100 2.6400 3.9300 1.9900 5.1800 2.8000 5.3300 5.5200 5.6800 3.5100 5.3700 4.2200 5.5400 6.0700 11.3000 4.4100 3.9800 4.3400 4.2100 4.6000 6.7600 4.4400 68.6500 84.5400 67.0700 66.9000 54.5000 76.8100 0.0500 0.0200 0.0400 0.0400 0.0800 0.0300 0.1100 0.2100 0.1100 0.2600 0.4700 0.1500 0.1500 0.0300 0.2000 0.0400 0.0400 0.0400 0.6500 0.3100 0.6300 0.5800 0.2900 0.1800 2.1500 0.7100 2.4900 2.2500 3.1700 1.4300 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 64 Sample Tank No. 65 Sample Tank No. 66 Sample Tank No. 67 Sample Tank No. 68 Sample Tank No. 69 Tank No. 18 Tank No. 19 Tank No. 20 Tank No. 21 Tank No. 22 Tank No. 23 139.887 70.761 171.538 38.394 215.631 148.757 89.426 46.290 110.120 12.834 164.956 138.780 21.590 4.142 15.382 16.424 8.875 1.515 1.190 2.570 1.670 0.720 4.240 5.310 0.011 0.371 0.013 0.224 0.985 1.086 0.035 0.697 0.017 0.209 0.787 0.854 0.010 0.039 0.004 0.007 0.020 0.025 0.025 0.176 0.025 0.066 0.118 0.122 1.109 1.292 1.613 0.216 2.331 3.227 0.000 0.000 0.000 0.000 0.000 0.000 30 25 31 23 17 20 60 136 64 79 86 120 14.7 14.7 14.7 14.7 14.7 14.7 60 136 64 79 86 120 0.94 0.916 0.938 0.908 0.946 0.932 380 431 340 324 323 326 25.0 27.0 27.0 29.0 29.0 29.0 500 500 500 500 500 500 4.90 3.30 5.20 3.10 4.80 4.90 16.66 6.76 18.46 6.36 20.11 11.50 1966.88 2041.97 1887.18 1405.21 2354.30 2985.81

0.0000 0.3800 0.2400 0.0000 0.2700 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0600 0.2200 0.2100 0.0900 0.0800 0.0300 0.0400 0.1000 0.3000 0.0000 0.0000 0.0000 1.3500 0.3200 0.8600 1.1200 0.4400 0.0800 0.8500 0.4100 0.5400 0.5300 0.7000 0.2000 2.0900 1.0700 1.7500 0.7000 2.0600 1.3000 1.1400 0.5700 1.1600 0.4500 0.9700 1.0400 2.7100 1.4500 3.1500 0.6300 2.7500 3.8800 2.1900 1.5700 2.9100 0.6400 2.7000 2.2100 2.4600 1.5100 2.5900 0.4600 2.3200 3.2000 2.2400 2.5400 3.7200 0.8400 3.5000 2.5500 5.7900 3.5300 5.8600 4.7900 8.3100 7.2000 4.7900 4.9600 5.6200 8.9000 7.2900 7.2300 4.4800 4.1700 3.7300 5.8000 7.0500 4.7500 66.3000 72.0600 63.8500 67.7100 53.9500 59.2600 0.0300 0.4300 0.0300 1.0000 1.2400 1.1600 0.2900 1.9600 0.1200 2.7600 2.8500 2.3500 0.2200 0.2400 0.0800 0.2400 0.1800 0.1600 0.6500 1.2100 0.5400 2.5900 1.2300 0.8600 2.3200 1.3000 2.7400 0.7500 2.1100 2.5400 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 70 Sample Tank No. 71 Sample Tank No. 72 Sample Tank No. 73 Sample Tank No. 74 Sample Tank No. 75 Tank No. 24 Tank No. 25 Tank No. 26 Tank No. 27 Tank No. 28 Tank No. 29 243.873 502.831 13.397 154.387 119.805 263.134 151.292 330.274 4.231 125.001 48.333 168.558 7.881 124.465 6.395 4.603 45.716 54.016 2.480 13.120 0.070 10.900 1.090 3.440 0.188 0.954 0.008 0.053 0.189 0.435 0.276 1.256 0.003 0.110 0.076 0.413 0.007 0.086 0.000 0.031 0.004 0.046 0.114 0.732 0.008 0.305 0.033 0.285 1.896 10.096 0.055 10.401 0.785 2.257 0.000 0.000 0.000 0.000 0.000 0.000 22 280 4 25 64 80 98 106 80 180 70 77 14.7 14.7 14.7 14.7 14.7 14.7 98 106 80 180 70 77 0.917 0.921 0.893 0.916 0.898 0.896 311 450 313 304 368 309 29.0 30.0 30.0 30.0 30.0 33.0 500 500 500 500 500 500 6.20 4.80 2.60 2.70 2.80 2.20 24.26 61.80 2.34 11.76 18.78 32.78 2141.84 1933.26 1394.74 2814.20 1478.45 1920.70

1.0100 0.0000 0.0000 0.0300 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1100 0.1200 0.0200 0.2700 0.1700 0.0300 0.0000 0.0500 0.0000 0.0000 0.0200 0.0200 0.4000 7.9800 0.5900 0.2600 3.1300 2.9000 1.6600 1.5600 0.4000 0.4800 0.7000 1.1000 2.2300 2.8200 0.5500 0.8100 1.0700 1.7100 1.1500 1.4300 0.4500 0.3600 0.8800 1.0700 1.9500 2.4400 0.6300 1.1800 1.1100 1.1500 2.8400 2.1200 0.4800 1.2900 1.0500 1.5000 1.3600 2.0900 0.4500 2.0600 1.0000 1.2300 3.0700 2.5400 1.0000 2.6800 1.5300 2.3300 6.9000 6.3500 4.3100 6.5200 4.4300 6.0000 7.6500 8.0300 4.9000 7.3900 5.8900 8.7700 5.8200 3.5600 4.1700 4.8600 4.2200 6.3100 61.2100 54.9600 80.5100 68.2000 72.4400 60.3600 0.1500 0.2000 0.0900 0.0200 0.3100 0.3800 0.6100 0.6800 0.1100 0.0900 0.3800 1.0700 0.0400 0.1100 0.0200 0.0500 0.0500 0.3100 0.7000 1.0600 0.8100 0.5400 0.5000 2.2000 1.1400 1.9000 0.5100 2.9100 1.1200 1.5600 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 76 Sample Tank No. 77 Sample Tank No. 78 Sample Tank No. 79 Sample Tank No. 80 Sample Tank No. 81 Tank No. 30 Tank No. 31 Tank No. 32 Tank No. 33 Tank No. 34 Tank No. 35 75.697 67.111 33.481 98.139 246.837 206.565 48.997 21.176 9.640 41.538 186.576 136.694 15.026 39.198 18.906 45.393 13.777 5.258 1.330 0.460 0.290 1.230 7.150 4.120 0.115 0.055 0.025 0.118 1.477 0.060 0.088 0.025 0.040 0.085 1.336 0.122 0.010 0.002 0.004 0.008 0.030 0.010 0.038 0.011 0.023 0.165 0.263 0.100 1.075 0.362 0.196 0.852 4.047 3.833 0.000 0.000 0.000 0.000 0.000 0.000 20 60 18 40 18 15 115 78 70 110 80 108 14.7 14.7 14.7 14.7 14.7 14.7 115 78 70 110 80 108 0.885 0.866 0.875 0.87 0.923 0.887 280 324 277 297 346 272 33.0 34.0 34.0 34.0 35.0 35.0 500 500 500 500 500 500 3.10 2.00 2.20 3.20 4.70 4.50 8.96 12.60 6.20 16.18 24.36 18.78 1989.27 1308.40 1280.62 1473.81 2361.43 2135.62

0.0000 0.0000 0.0000 0.0000 0.0100 0.0500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0300 0.0500 0.0700 0.0400 0.0600 0.6100 0.0000 0.0000 0.0000 0.0100 0.0100 0.0500 0.8400 2.8100 1.1600 2.9100 0.6400 0.2600 0.3700 0.3100 0.2400 0.4400 1.0500 0.7800 0.9200 0.6200 0.4900 0.6800 2.2200 1.7400 1.0000 0.4700 0.4300 0.5800 0.8300 0.8400 1.3200 0.7300 0.6500 0.6300 2.7600 2.3700 1.3500 0.7100 0.8000 0.5300 2.1100 2.2400 1.2200 0.6600 0.7000 0.4900 3.1100 2.2500 1.8500 1.0800 1.2900 0.8900 3.5800 3.1500 4.6800 2.3500 3.6200 4.6300 11.4200 6.1800 5.5400 2.9600 5.5500 5.3100 11.2400 6.7100 3.8000 1.9300 3.8000 4.5800 8.3200 5.0700 74.8700 84.1900 78.1200 76.3800 40.2000 64.3300 0.1700 0.1100 0.1400 0.1000 1.6600 0.0500 0.3400 0.1500 0.6900 0.1900 4.4100 0.2700 0.0900 0.0300 0.1800 0.0400 0.2500 0.0500 0.3900 0.2000 1.2000 0.9800 2.5500 0.5900 1.2200 0.6400 0.8700 0.5900 3.5700 2.4100 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 82 Sample Tank No. 83 Sample Tank No. 84 Sample Tank No. 85 Sample Tank No. 86 Sample Tank No. 87 Tank No. 36 Tank No. 37 Tank No. 38 Tank No. 39 Tank No. 40 Tank No. 41 176.370 34.019 82.578 113.253 204.693 178.190 121.493 16.601 32.683 56.649 107.904 100.629 10.526 12.380 40.189 30.738 57.039 28.323 3.520 1.050 1.820 2.310 3.540 2.460 0.068 0.262 0.364 0.285 0.530 0.307 0.092 0.297 0.293 0.292 0.386 0.280 0.019 0.011 0.016 0.018 0.030 0.012 0.072 0.048 0.125 0.138 0.208 0.068 3.266 0.435 1.023 1.573 2.383 1.789 0.000 0.000 0.000 0.000 0.000 0.000 17 30 50 57 75 28 100 125 68 80 81 60 14.7 14.7 14.7 14.7 14.7 14.7 100 125 68 80 81 60 0.887 0.863 0.879 0.883 0.883 0.891 283 276 356 294 288 277 35.0 36.0 36.0 36.0 36.0 36.0 500 500 500 500 500 500 4.90 2.50 3.80 3.90 4.10 3.80 17.62 5.02 14.02 15.52 27.84 22.04 2307.25 1616.36 1437.32 1721.01 1718.90 1846.39

0.0000 0.0000 0.0000 0.0000 0.0000 0.2000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0900 0.0300 0.0300 0.0600 0.1400 0.0600 0.0100 0.0000 0.0100 0.0100 0.0100 0.0100 0.5300 0.9100 2.4200 1.5900 2.9000 1.3300 1.1100 0.3200 0.4500 0.7200 0.9500 0.9300 1.7600 0.5700 0.8100 1.1100 1.4500 1.7200 0.8000 0.3900 0.5400 0.7700 1.0000 0.4400 2.3800 0.5800 1.1700 1.6000 1.8400 1.9800 2.1600 0.6500 1.3400 1.5200 1.6700 1.2300 2.6700 0.5700 1.6000 1.6700 1.7900 2.2100 3.3700 1.0700 2.4800 2.5900 2.1500 2.4300 6.0700 3.3600 7.6400 7.1400 6.1000 9.4100 6.8700 5.7300 10.3500 9.7000 7.9700 10.5500 6.0400 4.2600 5.9100 5.1000 5.2600 6.0500 62.5300 77.9200 57.3100 59.8700 61.4100 54.5600 0.0700 0.5500 0.8300 0.5000 0.5100 0.6300 0.2600 1.5800 2.0500 1.5100 1.0900 1.8200 0.1300 0.1300 0.2900 0.2400 0.2200 0.2100 0.5600 0.6500 2.6900 2.1000 1.7300 1.4100 2.5900 0.7300 2.0800 2.2000 1.8100 2.8200 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 88 Sample Tank No. 89 Sample Tank No. 90 Sample Tank No. 91 Sample Tank No. 92 Sample Tank No. 93 Tank No. 42 Tank No. 43 Tank No. 44 Tank No. 45 Tank No. 46 Tank No. 47 264.744 77.810 341.571 746.422 120.452 114.826 197.667 45.796 126.289 598.797 71.033 53.659 4.156 20.047 121.935 12.450 24.855 41.873 5.070 1.720 2.060 7.990 1.310 1.960 0.536 0.269 0.294 3.587 0.126 0.496 6.120 0.232 0.161 0.449 0.199 0.291 0.040 0.014 0.036 0.061 0.009 0.009 0.205 0.121 0.106 0.072 0.077 0.052 3.677 1.081 1.462 3.820 0.900 1.109 0.000 0.000 0.000 0.000 0.000 0.000 18 18 190 22 24 60 95 98 70 50 68 72 14.7 14.7 14.7 14.7 14.7 14.7 95 98 70 50 68 72 0.9 0.871 0.861 0.918 0.872 0.863 288 270 270 372 239 318 36.0 37.0 37.0 37.0 38.0 38.0 500 500 500 500 500 500 7.20 3.90 3.00 4.90 3.60 4.50 23.68 10.02 53.74 67.22 15.46 17.44 2352.89 1820.80 1489.35 2491.03 1867.10 1590.85

0.8700 0.0000 0.0000 0.1400 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1200 0.0500 0.3100 0.5300 0.0200 0.0500 0.0200 0.0000 0.0300 0.0000 0.0000 0.0000 0.1900 1.0400 6.2500 0.5600 1.1400 2.5500 0.6800 0.4200 2.2000 2.3100 0.5800 0.8600 2.5400 0.9700 2.0200 4.1000 1.2600 1.3500 1.1400 1.1500 0.5500 1.9100 0.9300 0.9700 3.8100 1.3100 1.1800 5.0000 1.4400 1.3600 2.9900 1.6600 0.8300 3.4000 1.6100 1.4200 2.9100 1.2800 0.7100 3.5100 1.3900 1.3400 3.7100 2.1200 1.3200 3.0200 2.3200 2.1100 9.0500 5.2700 3.8300 13.2800 6.5000 5.5300 7.1100 7.7200 6.7800 13.1300 8.7200 7.6500 5.9500 4.7200 2.8000 5.9600 5.9100 5.6600 52.8400 67.1300 69.1900 36.1900 62.7500 64.2400 0.4700 0.5000 0.1800 2.6100 0.3100 0.8400 1.5000 1.1900 0.3000 1.0600 1.5000 1.4900 0.2400 0.1800 0.1800 0.4000 0.1800 0.1200 1.4100 1.7200 0.6100 0.5500 1.7900 0.8100 2.4500 1.5700 0.7300 2.3400 1.6500 1.6500 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 94 Sample Tank No. 95 Sample Tank No. 96 Sample Tank No. 97 Sample Tank No. 98 Sample Tank No. 99 Tank No. 48 Tank No. 49 Tank No. 50 Tank No. 51 Tank No. 52 Tank No. 53 54.705 437.309 165.905 279.758 608.810 254.487 37.588 181.269 149.208 103.605 571.582 161.927 8.963 1.079 0.600 12.141 8.030 48.433 2.550 4.660 4.640 1.630 17.380 7.830 0.263 0.041 0.202 0.453 0.424 2.228 0.317 0.110 0.380 0.085 0.458 1.268 0.024 0.053 0.035 0.015 0.025 0.039 0.218 0.149 0.168 0.017 0.441 0.399 1.726 4.311 3.855 1.063 16.032 3.892 0.000 0.000 0.000 0.000 0.000 0.000 32 62 13 28 22 66 149 80 113 45 114 89 14.7 14.7 14.7 14.7 14.7 14.7 149 80 113 45 114 89 0.862 0.894 0.882 0.904 0.877 0.877 251 310 294 294 337 282 38.0 38.0 38.0 38.0 38.0 39.0 500 500 500 500 500 500 3.00 5.20 5.70 7.40 3.10 3.70 5.82 37.60 13.60 28.24 45.82 30.08 2216.65 1206.29 2853.46 1313.43 3053.30 1945.58

0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0100 4.1200 0.0100 2.0000 0.0400 0.1800 0.0000 0.0200 0.0000 0.0000 0.2000 0.0000 0.5100 0.0500 0.0300 0.5300 0.4200 2.2600 0.4400 0.3200 0.4500 1.0400 0.5700 0.8400 0.5900 1.4800 2.4200 1.9800 2.1600 1.4800 0.5400 0.8700 1.1900 1.4200 1.1400 1.0300 0.6500 3.3500 3.2300 3.7800 4.2600 1.6000 1.3500 3.0800 2.0600 2.9700 2.9000 2.0600 1.1500 2.8200 3.0500 2.9500 4.2900 1.8600 2.5000 4.7100 2.3400 2.6800 3.5200 3.4100 6.4600 10.0400 7.7900 11.8900 10.3400 8.6400 8.5600 11.8100 8.3700 11.7900 9.9300 11.0300 3.4500 6.4100 6.4400 6.6500 4.4300 5.1000 69.3200 46.8100 57.0400 45.6300 51.0200 51.2400 0.3200 0.0300 0.2000 1.1100 0.1100 1.6600 0.9100 0.2400 0.9900 0.7100 0.3100 2.6900 0.1500 0.3000 0.2100 0.3600 0.0400 0.2100 1.4800 0.9700 1.1500 0.4800 0.7800 2.4200 1.6100 2.5700 3.0300 2.0300 3.5400 2.2900 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Sample Tank No. 100 Sample Tank No. 101 Sample Tank No. 102 Sample Tank No. 103 Tank No. 54 Tank No. 55 Tank No. 56 Tank No. 57 173.095 363.718 391.465 274.631 97.629 237.995 191.567 204.825 52.151 56.163 3.830 22.453 4.410 2.820 5.090 19.640 0.242 0.369 0.970 5.674 0.281 0.045 0.836 4.267 0.031 0.026 0.019 0.070 0.164 0.129 0.135 0.436 3.689 2.253 3.127 9.194 0.000 0.000 0.000 0.000 60 60 33 42 80 58 60 110 14.7 14.7 14.7 14.7 60 58 60 110 0.891 0.877 0.907 0.879 265 309 295 283 39.0 39.0 39.0 39.0 500 500 500 500 5.60 6.80 6.40 5.40 23.36 43.14 36.04 26.60 1766.66 2016.56 1509.76 2428.31

0.0000 0.0000 0.1100 0.0000 0.0000 0.0000 0.0000 0.0000 0.0500 0.0300 2.4000 0.0100 0.0100 0.0100 0.0000 0.0000 2.3200 2.6700 0.1600 1.0900 0.7200 1.7300 0.7600 1.5000 1.1900 3.6000 2.6400 2.1200 0.8900 1.8800 0.9100 0.8400 1.8300 3.2300 3.5800 2.2800 2.3500 2.4900 2.6500 1.6400 3.2400 2.1100 3.4400 2.5200 3.9900 2.7200 3.7800 2.6100 9.9400 8.1600 10.7700 9.7300 11.5600 11.9800 11.8300 8.9300 6.0600 4.9500 6.1900 5.8900 48.9900 50.3400 40.8600 47.7300 0.3000 0.3800 1.2700 2.7500 1.0300 0.1500 3.4900 5.3000 0.2900 0.2400 0.2200 0.2000 1.7800 1.3700 1.8000 1.3900 3.4600 1.9600 3.1400 3.4700 0.0000 0.0000 0.0000 0.0000 100.0000 100.0000 100.0000 100.0000Tank ID API > 40

E&P Tank Number Average ratios to HAP Ratio to VOC Maximum Minimum Average Total Emissions (tpy) Total 785.812 8152.118 129.419 1530.229 VOC Emissions (tpy) VOC 530.750 33.837 5678.554 43.734 1046.343 Methane Emissions (tpy) Methane 116.167 7.406 0.219 1206.981 0.197 230.569 HAP Emissions (tpy) HAP 15.685 0.030 101.610 2.680 30.684 Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Pressure 126.451 870.000 13.000 231.870 Separator Temperature (F) Separator Temperature 88.657 140.000 40.000 82.500 Ambient Pressure (psia) Ambient Temperature (F) C10+ SG 0.893 0.929 0.801 0.873 C10+ MW 292.72 375.000 162.000 241.304 API Gravity API Gravity 40.6 68.0 40.0 52.8 Production Rate (bbl/day) Reid Vapor Pressure (psia) RVP 5.691 13.100 3.000 7.983 GOR (scf/bbl) GOR 88.149 924.960 12.300 172.479 Heating Value of Vapor (Btu/scf) Heating value 1968.085 LP Oil Component Composition H2S 0.0679 O2 0.0000 CO2 0.3661 N2 0.0360 C1 2.9248 C2 1.6262 C3 2.7564 i-C4 1.3958 n-C4 2.9738 i-C5 2.4711 n-C5 2.7194 C6 3.2723 C7 8.5230 C8 10.3202 C9 5.6686 C10+ 48.1339 Benzene 0.6044 Toluene 1.6882 E-Benzene 0.1797 Xylenes 1.4353 n-C6 2.8369 224Trimethylp 0.0000 100.0000Tank ID

E&P Tank Number Total Emissions (tpy) VOC Emissions (tpy) Methane Emissions (tpy) HAP Emissions (tpy) Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp Separator Pressure (psig) Separator Temperature (F) Ambient Pressure (psia) Ambient Temperature (F) C10+ SG C10+ MW API Gravity Production Rate (bbl/day) Reid Vapor Pressure (psia) GOR (scf/bbl) Heating Value of Vapor (Btu/scf) LP Oil Component H2S O2 CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7 C8 C9 C10+ Benzene Toluene E-Benzene Xylenes n-C6 224Trimethylp API <40 Maximum Minimum Average 746.422 13.397 174.327 598.797 3.087 107.227 124.465 0.115 22.193 19.640 0.070 3.366 5.674 0.003 0.445 6.120 0.003 0.431 0.086 0.000 0.019 0.732 0.001 0.120 16.032 0.052 2.449 0.000 0.000 0.000 280.000 4.000 39.857

0.984 0.861 0.910 551.000 239.000 334.946 39.0 15.0 30.6

7.400 0.600 3.809 67.220 2.340 18.878API Gravity >40 API Gravity <40 VOC Emissions (tpy) VOC Emissions (tpy)

Mean 1046.343 Mean 107.2265 Standard Error 188.1410357 Standard Error 15.51304 Median 530.989 Median 72.87 Mode #N/A Mode #N/A Standard Deviation 1276.034588 Standard Deviation 116.0889 Sample Variance 1628264.269 Sample Variance 13476.64 Kurtosis 3.35522263 Kurtosis 9.02191 Skewness 1.864492873 Skewness 2.680349 Range 5634.82 Range 595.71 Minimum 43.734 Minimum 3.087 Maximum 5678.554 Maximum 598.797 Sum 48131.778 Sum 6004.685 Count 46 Count 56 Largest(1) 5678.554 Largest(1) 598.797 Confidence Level(95.0%) 378.9354921 Confidence Level(95.0%) 31.08882

667.4075079 76.1377 VOC 1046.343 VOC 107.2265 1425.278492 138.3153United States Environmental Protection Agency Office of Air Quality Planning and Standards Sector Policies and Programs Division Research Triangle Park, NC EPA

- 453/R

- 11

- 002 July 2011