Oil and Natural Gas Sector: Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission, and 

Distribution.

Background Technical Support Document for Proposed Standards
EPA-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: 

EC/R, Incorporated

501 Eastowne Dr, Suite 250

Chapel Hill, North Carolina 27514

Prepared 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 Carolina
ii

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 oil 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 SO2, as well as any additional pollutants that are 

identified. This document is the result of that 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 process undertaken for this review. Finally, Chapters 4-8 provide 

information on previously unregulated emissions sources. Each chapter describes the emission source, 

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

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

estimated and the rationale for the proposed NSPS for each emission source is provided. 
TABLE OF CONTENTS

1.0NEW 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

2.0SECTOR DESCRIPTION ..............................................................................................................................2-1

3.0NEW SOURCE PERFORMANCE REVIEW PROCESS...........................................................................3-1

3.1Evaluation 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.......................................................................................................................................................4-32
5.0 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 Representative 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............................................................................................................................5-12

5.4.2.1 Emission Reduction Potential ..........................................................................................................5-12

5.4.2.2 Effectiveness....................................................................................................................................5-12

5.4.2.3 Cost Impacts.....................................................................................................................................5-14

5.4.2.4 Secondary Impacts...........................................................................................................................5-16

5.4.3 Instrument Air Systems...........................................................................................................................5-16

5.4.3.1 Description.......................................................................................................................................5-16

5.4.3.2 Effectiveness....................................................................................................................................5-18

5.4.3.3 Cost Impacts.....................................................................................................................................5-19

5.4.3.4 Secondary Impacts...........................................................................................................................5-22

5.5 Regulatory Option..........................................................................................................................................5-22

5.5.1 Evaluation of Regulatory Options...........................................................................................................5-22

5.5.2 Nationwide Impacts of Regulatory Options............................................................................................5-24

5.6 References.......................................................................................................................................................5-26

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 Transmission 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...........................................................................6-12

6.4.2.1 Description.......................................................................................................................................6-12

6.4.2.2 Effectiveness....................................................................................................................................6-12

6.4.2.3 Cost Impacts.....................................................................................................................................6-16

6.4.2.4 Secondary Impacts...........................................................................................................................6-18

6.4.3 Centrifugal Compressor Dry Seals .........................................................................................................6-18
6.4.3.1 Description.......................................................................................................................................6-18

6.4.3.2 Effectiveness....................................................................................................................................6-19

6.4.3.3 Cost Impacts.....................................................................................................................................6-19

6.4.3.4 Secondary Impacts...........................................................................................................................6-21

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........................................................................................................................................6-23

6.5.1 Evaluation of Regulatory Options...........................................................................................................6-27

6.5.2 Nationwide Impacts of Regulatory Options............................................................................................6-28

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 and Emission Factors....................................................................................8-1

8.2.2 Model Plant...............................................................................................................................................8-2
8.2.2.1 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 A
1-1

1.0 NEW SOURCE PERFORMANCE STANDARD BACKGROUND

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 anticipated to endanger public health 

or welfare.” This technical support document (TSD) supports the proposed standards, which would 

control volatile organic compounds (VOC) and sulfur dioxide (SO2) emissions from the oil and natural 

gas sector.

1.1 Statutory Authority

Section 111 of the Clean Air Act (CAA) requires the Environmental 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” 

(BSER) 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 issued 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 and, if appropriate, revise” 

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

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

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

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

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

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

system of emission reduction which (taking into account the cost of achieving such reduction and any 
1-2

non-air quality health and environmental impact and 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 emission 

reduction systems exist and how much the identified systems reduce air pollution in practice. For 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 such 

standards are based on the BSER, the EPA may not prescribe a particular technology that must be used 

to comply with a performance standard, except in instances where the Administrator determines it is not 

feasible to prescribe or enforce a standard of performance. Typically, sources remain free to elect 

whatever control measures that they choose to meet the emission limits. Upon promulgation, a NSPS 

becomes a national standard to which all new, modified or reconstructed sources must comply.

1.2 History of Oil and Natural Gas Source Category

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

promulgation of NSPS (44 FR 49222, August 21, 1979). On June 24, 1985 (50 FR 26122), the EPA 

promulgated 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 (SO2) 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 subpart LLL addresses SO2 emissions from natural gas 

processing plants.

1.3 NSPS Review Process Overview

CAA section 111(b)(1)(B) requires EPA to review and revise, if appropriate, NSPS standards. First, the 

existing NSPS were evaluated to determine whether it reflects BSER for the emission affected sources. 

This review was conducted by examining control technologies currently in use and assessing whether 
1-3

these technologies represent advances in emission reduction techniques compared to the technologies 

upon which 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 such as solid waste 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 regulated pollutants, VOC and SO2, 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 production, (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 

include 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 related casing head, tubing head and 

“Christmas tree” piping, as well as pumps, compressors, heater treaters, separators, storage vessels, 

pneumatic devices and dehydrators. Production operations also include well drilling, completion and 

recompletion processes; which includes all the portable non-self-propelled apparatus associated with 

those operations. Production sites include not only the “pads” where the wells are located, but also 

include stand-alone sites where oil, condensate, produced water and gas from several wells may be 

separated, stored and treated. The production 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 the 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 connected 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” natural 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. The oil refinery sector is considered 
2-2

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 (NGL). They are sold 

separately and have a variety of different uses. The raw natural gas often contains water vapor, hydrogen 

sulfide (H2S), carbon dioxide (CO2), helium, nitrogen and other compounds. Natural gas processing 

consists of separating certain hydrocarbons and fluids from the natural gas to produced “pipeline 

quality” dry natural gas. While some of the processing can be accomplished in the production segment, 

the complete processing of natural gas takes place in the natural gas processing segment. Natural gas 

processing operations separate and recover 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, water removal, separation of natural gas liquids, sulfur and 

CO2 removal, fractionation of natural gas liquid and other processes, such as the capture of CO2

separated from natural gas streams for delivery outside the facility. 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 flowing through any pipeline remains pressurized, compression of 

the gas is required periodically along the pipeline. This is accomplished by compressor stations usually 

placed between 40 and 100 mile intervals along the pipeline. At a compressor station, the natural gas 

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

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

an underground storage site, there are typically other processes, including compression, dehydration and 

flow measurement.
2-3

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

the distribution segment from delivery points located on interstate and intrastate transmission pipelines 

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

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

ownership of the gas at the citygate. Natural gas distribution systems consist of thousands of miles of 

piping, including mains and service pipelines to the customers. Distribution systems sometimes have 

compressor stations, although they are considerably smaller than transmission compressor stations. 

Distribution systems include metering stations, which allow distribution companies to monitor the 

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

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

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

Primarily, these emissions are organic compounds such as 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 SO2 are emitted from production and 

processing operations that handle and treat sour gasi

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

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

emissions from internal combustion engines and combustion turbines are covered by regulations specific 

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

 

i

Sour gas is defined as natural gas with a maximum H2S content of 0.25 gr/100 scf (4ppmv) along with the presence of CO2
Figure 2-1. Oil and Natural Gas Operations

2-4
3-1

3.0 NEW SOURCE PERFORMANCE STANDARD 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 SO2

emissions from sweetening units located at natural gas processing 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, if appropriate, NSPS 

standards. This review process consisted of the following steps:

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

emission sources that they address;

2. Evaluation of whether there were additional pollutants emitted by facilities in the oil and natural 

gas sector that warrant regulation and for which there is adequate information to promulgate 

standards of performance; 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 identified 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 specific 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 LDAR 
3-2

program is considered to be more stringent than the subpart VV requirements, 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. 

Options based on optical gas imaging were also reviewed.

The 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 concentration 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, 

these instruments do not yet provide a direct measure of leak concentrations. The instruments 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 Provisions 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.

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

evaluated. 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 plants 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 individual 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 

component-by-component analyses are provided 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 was 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 

optical 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 was 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 

$3,950 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 monthly optical gas imaging without an annual Method 21 check. 

The 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 subpart VVa LDAR. 

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

For 40 CFR part 60, subpart LLL, control systems for SO2 emissions from sweetening units located at 

natural gas processing plants were evaluated, including those 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 SO2 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 process for converting H2S in acid gases (i.e., 

H2S and CO2) 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 H2S in the feed stream due to the thermodynamic equilibrium limitation of the Claus process. The 

Claus sulfur recovery unit produces elemental sulfur from H2S in a series of catalytic stages, recovering 

up to 97-percent recovery of the sulfur from the acid gas from the 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 treatment 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 sulfur 

feed rate and inlet H2S 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 H2S and CO2 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 of 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 The emission limit for sulfur 

feed rates at or below 5 long tons per day, regardless of H2S 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 H2S content 

below 10 percent to 99.8 percent for H2S contents at or above 50 percent.

To review these emission limitations, a search was performed of the RBLC database1and state 

regulations. No State 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 SO2

 

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 facility 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 H2S contents of the feed stream. Because the sulfur recovery 

efficiency of these large sized plants was greater than 99.8 percent, the original data was reevaluated. 

Based on the available 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 H2S content equal to or greater than 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 H2S content equal to or greater than 50 percent is raised to 99.9 

percent. 

The search of the RBLC 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 H2S 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 H2S 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 SO2. 

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-

equivalents (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 this 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-GHGInventory2010_ExecutiveSummary.pdf
3-6

This adjustment would increase the 2009 Inventory estimate by 76.74 MMtCO2e. The total methane 

emissions from Petroleum and Natural Gas Systems, based on the 2009 Inventory, adjusted for tight

sand plays and the Marcellus, is 328.29 MMtCO2e. 

Although this proposed rule does not include standards for regulating the GHG emissions discussed 

above, EPA continues 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 (NOx) also occur at oil and natural gas sites due to the 

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

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

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

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

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

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

Standards of Performance for Stationary Combustion Turbines (40 CFR part 60, subpart KKKK), 

respectively.

An additional source of NOx emissions would be pit flaring of VOC emissions from well completions. 

As discussed in Chapter 4 Well completions, pit flaring is one option identified for controlling VOC 

emissions. Because there is no way of directly measuring the NOx 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 SO2 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 SO2 is expected to be emitted directly; although H2S contained in

sour gasvforms SO2 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 

category 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 H2S content of 0.25 gr/100 scf (4ppmv) along with the presence of CO2.
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 gas processing plants, there are numerous sources of VOC 

throughout the oil and natural gas sector that are not addressed by the current NSPS. Pursuant 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 vessels. 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 document 

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 RECOMPLETIONS

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 the atmosphere during flowback. Flowback emissions are shortterm 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 reduce 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 flowback 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 activities not only will vary across formations, but can vary between wells in 

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

of well characteristics and technology advancement. 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 lines 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.2
4-2

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 temperature from the formation need to be ascertained before surface 

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

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

vent or combust the flowback gas. 

One completion step for improving 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 after fluid pressure is reduced. Natural gas emissions are a result of the backflow of the fracture 

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

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

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

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

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

the nature of the backflow of the fracture fluids, completions involving hydraulic fracturing have higher 

costs and vent substantially more natural gas than completions not involving hydraulic fracturing.

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 that 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 will 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 production. 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 malfunctioning downhole 

pump. During a recompletion, portable equipment is conveyed back to the well site temporarily and 

some recompletions require the use of a service rig. As with well completions, recompletions are highly 

specialized activities, requiring special equipment, and are usually performed by well service contractors 

specializing in well maintenance. Any flowback event during a recompletion, such as after a hydraulic 

fracture, will result in emissions to the atmosphere unless the flowback gas is captured. 

When hydraulic re-fracturing 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 water 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 backflow 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 dissolved in the fluid 

when it enters the impoundment or vessels.

4.2. Emission Data and Emissions Factors

4.2.1 Summary of Major Studies and Emission Factors

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 along with an indication of the type of information 

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 Emissions 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 

State14

Independent 

Petroleum Association 

of America

2009 Nationwide

Emissions from Natural Gas Production in the 

Barnett Shale and Opportunities for Costeffective 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 Nationwide
Table 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 Data17

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 X
4-6

4.2.2 Representative Completion and Recompletion Emissions

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

the venting of natural gas to the atmosphere during flowback. Flowback emissions are short-term in 

nature and occur as a specific event during the completion of a new well or during recompletion 

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

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

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 available 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 horizontally 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, methane 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 and 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 methane (lb VOC/lb methane) and 0.0106 lb HAP/lb methane. The specific gas 

composition ratios used for oil wells were 0.8374 pounds lb VOC/lb methane and 0.0001 lb HAP/lb 

methane.

The EPA’s analysis to estimate methane emissions conducted in support of the Greenhouse Gas 

Mandatory 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 oil well 

completions, oil well recompletions, 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 recompletion 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 Methanea VOCb HAPc

Natural Gas Well Completion without 

Hydraulic Fracturing 38.6 0.8038 0.12 0.009

Natural Gas Well Completion with 

Hydraulic Fracturing 7,623 158.55 23.13 1.68

Oil Well Completions 0.34 0.0076 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 0.00126 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.
4-8

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 reduction credit was attributed to sources already controlled under State regulations, it was 

necessary to account for the number of completions/recompletions 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 regulation 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. 

New 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 wells 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 assumed 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 discussion 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 operator, 

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 historical 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 that would occur in 

a representative year. The number of hydraulically fractured natural gas recompletions 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 Document3). 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 of 

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/DataExports.aspx
4-10

recompletions were based on well data for 2008 in HPDI. The number of estimated well completions 

and recompletions for each well source category 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 evaluated, 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 

recompletions 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 and recompletions. Although there may be 

regulations issued by other local ordinances for cities and counties throughout the U.S., wells impacted 

by these regulations were not included in this analysis because well count data are not available on a 

county 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 States identified as requiring controls on completions 

prior to NSPS review. The State of Wyoming’s Air Quality Division (WAQD) requires operators to 

complete wells without flaring or venting where the following criteria are met: (1) the flowback gas 

meets sales line specifications and (2) the pressure of the reservoir is high enough to enable REC. If the 

above criteria are not met, then the produced gas is to be flared. 27 The WAQD requires that, “emissions 

of VOC and HAP associated with the flaring and venting of hydrocarbon fluids (liquids and gas) 

associated with well completion and recompletion activities shall be eliminated to the extent practicable 

by routing the recovered liquids into storage tanks and routing the recovered gas into a gas sales line or 

collection system.” Similar to 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.htm
4-11

Table 4-3: Estimated Number of Total Oil and 

Natural Gas Completions and Recompletions for a Typical Year

Well Completion Category

Estimated Number 

of Total 

Completions and 

Recompletionsa

Estimated 

Number of 

Controlled 

Completions and 

Recompletions

Estimated 

Number of 

Uncontrolled 

Completions and 

Recompletionsb

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 Fracturingc 10,957 1,644 9,313

Oil Well Completionsd

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 directly 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 State 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 that may be used separately or in tandem, depending on the individual 

State regulation.vThe final activity factors for uncontrolled completions and uncontrolled recompletions 

are also listed in Table 4-3.

4.3.4 Emission Estimates

Using the estimated emissions, number of uncontrolled and controlled wells at baseline, described 

above, nationwide 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 independently 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 completions 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 of 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 flares was not determined and no secondary baseline emission impacts were calculated.
4-13

Table 4-4. Nationwide Baseline Emissions from Uncontrolled Oil and Gas Well 

Completions and Recompletions

Well Completion 

Category

Uncontrolled 

Methane 

Emissions per 

event

(tpy)

Number of 

Uncontrolled 

Wellsa

Baseline Nationwide Emissions 

(tons/year)a

Methaneb VOCc HAPd

Natural Gas Well 

Completions without 

Hydraulic Fracturing

0.8038 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 2,279 332 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 assumption 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 venting and results in additional economic benefit from the sale 

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

include additional tankage, special gas-liquid-sand separator traps, and a gas dehydrator.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 limitations exist for performing RECs 

since technical barriers fluctuate from well to well. Three main limitations include the following for 

RECs:

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

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

and/or pipeline companies constructing lines in exploratory fields. The State of Wyoming has 

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

avoid RECs unless they are deemed exploratory, or the first well drilled in an area that has 

never had oil and gas well production prior to that drilling instance (i.e., a wildcat well).

30 In 

instances where formations are stacked vertically and horizontal 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 of flowback fluids may not be sufficient to overcome the sales line backpressure. 

This pressure is dependent on the specific sales line pressure and can be highly variable. In 

this case, combustion of flowback gas is one option, either for the duration of the flowback or 

until a point during flowback when the pressure increases to flow to the sales line. Another 

control option is compressor applications. One application is gas lift which is accomplished 

by withdrawing gas from the sales line, boosting its pressure, and routing it down the well 
4-15

casing to push the fracture fluids up the tubing. The increased pressure facilitates flow into 

the separator and then the sales line where the lift gas becomes part of the normal flowback 

that can be recovered during a REC. Another potential compressor application is to boost 

pressure of the flowback gas after it exits the separator. This technique is experimental 

because of the difficulty operating a compressor on widely fluctuating flowback rate.

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

increases to allow flow to the sales line. Further, since the energy content of the flowback gas 

may not be high enough to sustain a flame due to the presence of the inert gases, combustion 

of the flowback stream would require a continuous ignition source with its own separate fuel 

supply. 

4.4.2.2. Effectiveness

RECs are an effective emissions reduction method for only natural gas completions and recompletions 

performed with hydraulic fracturing based on the estimated flowback emissions described in Section 

4.2. The emissions reductions vary according to reservoir characteristics and other parameters including 

length of completion, number of fractured zones, pressure, gas composition, and fracturing 

technology/technique. Based on 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 normal operations, costs may be reduced 

as this equipment can be used or resized rather than installing a portable dehydrator for temporary use 

during the completion. Some operators normally install equipment used in RECs, such as sand traps and 

three-phase separators, further reducing incremental REC costs. 
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 involve 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-time events per well; therefore annual costs were 

conservatively assumed to be the same as capital costs. Dividing by the expected emission reductions, 

cost-effectiveness for VOC is $1,429 per ton, with 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 $4.00vii 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/

Recompletionb

($/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 hydraulic 

fracturing is approximately $33,030. In addition we estimate an average of 34 barrels 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 impacts 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 completion 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 discharge over a pit near the wellhead. However, the flow directed 

to a completion combustion device may or may not be combustible depending on the inert gas 

composition of flowback gas, which would require a continuous ignition source. Sometimes referred to 

as pit flares, these types of combustion devices do not employ an actual control device, and are not 

capable of being tested or monitored for efficiency. They do provide a means of minimizing vented gas 

and is preferable to venting. For the purpose of this analysis, the term completion combustion device 

represents all types of combustion devices including pit flares.
4-19

4.4.3.2 Effectiveness

The efficiency of completion combustion devices, or exploration and production flares, 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 the combustion mechanism can be extinguished by the flowback gas. 

Therefore, it is more reliable to install an igniter fueled by a consistent and continuous ignition source. 

This scenario would be especially true for energized fractures where the initial flowback concentration 

will be extremely high in inert gases. This analysis assumes 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. Additionally, because of the nature of the flowback (i.e., with periods of water, 

condensate, and gas in slug flow), conveying the entire portion of this stream to a flare or other control 

device is not always feasible. Because of the exposed flame, open pit flaring 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 from well completions and recompletions.

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 

Engineering, 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 representative 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 responsible 

for the outliers, but also 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, costs were estimated as the total cost 

of the completion combustion device itself, which corresponds to the assumption that only one device 

will control one completion per year. The cost impacts of using a completion combustion device to 

reduce emissions from representative completions/recompletions are provided in Table 4-6. Completion 

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 outcomes of completion combustion device operation. In 

addition, combustion and partial combustion of many pollutants also create secondary pollutants 

including nitrogen oxides (NOx), carbon monoxide (CO), sulfur oxides (SOx, carbon dioxide (CO2), 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 

circumstances (e.g., energized fractures). The stream to be combusted may also contain liquids and 

solids that will also affect the potential for smoke. Soot can typically be eliminated by adding steam. 

Based on current industry trends in the design of completion combustion devices and in the 

decentralized nature of completions, virtually no completion combustion devices include steam 

assistance.34

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

Guidelines published in AP-42 for flare operations are based on tests from a mixture containing 

 

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 472,227 68,889

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 stated 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 Table 4-7. 

Since this analysis assumed pit flares achieve 95 percent efficiency over the duration of flowback, it is 

likely the secondary emission estimations are lower than actuality (i.e. AP-42 assumes 98 percent 

efficiency). In addition due, to the potential for the incomplete combustion of natural gas across the pit 

flare plume, the likelihood of additional NOx 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 flame temperature. 

Moreover, the actual NOx (and CO) emissions may be greatly affected when the raw gas contains

hydrocarbon liquids and water. For these reasons, the nationwide impacts of combustion devices 

discussed in Section 4.5 should be considered minimum estimates of secondary emissions from 

combustion devices.

4.5 Regulatory Options

The REC pollution prevention approach would not result in emissions of CO, NOx, 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 

evaluated:

 Regulatory Option 1: Require 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 combustion devices for all 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 hydraulic fracturing, with the exception of exploratory, and delineation wells; 

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

wells; and 
4-23

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

a

Pollutant Emission Factor

(lb/106 Btu)

Total Hydrocarbonb0.14

Carbon Monoxide 0.37

Nitrogen Oxides 0.068

Particular Matterc0-274

Carbon Dioxided60 

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 carbon 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 these 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 

recompletions) 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 $31,600 

per ton VOC to over $3.7 million per ton VOC. Therefore, Regulatory Options 1 and 2 were rejected 

due to the high cost effectiveness.

The next regulatory option, to require completion combustion devices for all completions and 

recompletions, was considered. Under Regulatory Option 3, all of the natural gas emitted from the well 

during flowback would be destroyed by sending flowback gas through a combustion unit. Not only 

would this regulatory 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 require RECs 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 activities 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 combustion 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 

represents the best system of continuous emission reduction, provided the following criteria are met: 

“(A) a pollutant or pollutants cannot be emitted through a conveyance designed and constructed 

to emit or capture such pollutant, or that any requirement for, or use of, such a conveyance would 

be inconsistent with any Federal, State, or local law, or 

(B) the application of measurement methodology to a particular class of sources is not 

practicable due to technological or economic limitations.”

As discussed in section 4.4.3, emissions from a completion combustion device cannot be measured or 

monitored to determine efficiency making an operational standard appropriate. Therefore, an operational 

standard under this regulatory option consists of a combination of REC and a completion combustion 

device to minimize the venting of natural gas and condensate vapors to the atmosphere, but allows 

venting in lieu of combustion for situations in which combustion would present safety hazards, other 

concerns, or for periods when the flowback gas is noncombustible due to high concentrations of inert 

gases. Sources would also be required, under this regulatory option, to maintain documentation of the 

overall duration of the completion event, duration of recovery using REC, duration of combustion, 

duration of venting, and specific reasons for venting in lieu of combustion. It was also evaluated whether 

Regulatory Option 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 wells 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 the relatively 

unknown characteristics of the formation, completion activities occurring at exploratory or delineation 

wells were considered to be a different “type” of activity than the types of completion activities 

occurring at all other gas wells. Therefore, two subcategories of completions were identified: 

Subcategory 1 wells are 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 meet the 

following definitions 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 feasible. Therefore, this 

regulatory option requires an operational standard where emissions are minimized using a completion 

combustion device during completion activities at Subcategory 2 wells, with an allowance for venting in 

situations where combustion presents safety hazards or other concerns or for periods when the flowback 

gas is noncombustible due to high concentrations of inert gases. Consistent with Regulatory Option 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 necessary 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 regulatory 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 modification 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 source or which results in the emission 

of any air pollutant not previously emitted.” 

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

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

valve. In order to fracture an existing well during recompletion, the well would be re-perforated, causing 

physical change to the wellbore and casing and therefore a physical change to the wellhead, the affected 

facility. Additionally, much of the emissions data on which this analysis is based demonstrates that 

hydraulic fracturing results in an increase in emissions. Thus, recompletions using hydraulic fracturing 

result in an increase in emissions from the existing well producing operations. Based on this 

understanding of the work performed in order to recomplete the well, it was determined that a 

recompletion would be considered a modification under CAA section 111(a) and thus, would constitute 

a new wellhead affected facility subject to NSPS. 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 impacts 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 Primary 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: Operational 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 operational standard for completions with hydraulic fracturing 

for exploratory and delineation wells (i.e., Subcategory 2 wells) which requires 

completion combustion devices with an allowance for venting during specified situations.

 Regulatory Option 7: An operational 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 

above was presented in Table 4-3. It was estimated that there would be 9,313 uncontrolled 

developmental natural gas well completions with hydraulic fracturing subject to Regulatory Option 5. 

Regulatory Option 6 would apply to 446 uncontrolled exploratory natural gas well completions with 

hydraulic fracturing, and 12,050 uncontrolled recompletions at existing wells would be subject to 

Regulatory Option 7.x

Table 4-8 presents the nationwide emission reduction estimates for each regulatory option. It was 

estimated that RECs in combination with the combustion of gas unsuitable for entering the gathering

line, can achieve an overall 95 percent VOC reduction over the duration of the completion 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 applying 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 Regulatory 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. Applied 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 likely 

be recompleted 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 completion combustion devices 

in Table 4-6.

c. Nationwide emission reductions 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 

NSPSa

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)

Subcategory 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)

Subcategory 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 considered. 

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 estimated 

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 composition, 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 

completions 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 hydraulic fracturing, it is assumed that 95 percent 

(8,716 Mcf) 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 emissions factors listed in Table 4-7.

From category 1 well completions and from recompletions, it is estimated 0.02 tons of NOx are 

produced per event. This is based on assumptions that 5 percent of the flowback gas is combusted by the 

combustion device. From category 2 well completions, it is estimated 0.32 tons of NOx are produced in 

secondary emissions per event. This is based on the assumption 95 percent of flowback gas is 

combusted by the combustion device. Based on the estimated number of completions and recompletions, 

the proposed regulatory options are estimated to produce around 507 tons of NOx in secondary 

emissions nationwide from controlling all or partial flowback by combustion. Table 4-9 summarizes the 

estimated secondary emissions of the selected regulatory options. 
4-31

Table 4-9 Nationwide Secondary Impacts of Selected Regulatory Optionsa

Pollutant

Regulatory Options 5b Regulatory Option 6c Regulatory Options 7b

Subcategory 1 Natural Gas 

Well Completions with 

Hydraulic Fracturing

Subcategory 2 Natural Gas 

Well Completions with 

Hydraulic Fracturing

Natural Gas Well 

Recompletions with Hydraulic 

Fracturing

tons per 

eventd

Nationwide 

Annual 

Secondary 

Emissions 

(tons/year)

tons per 

eventd

Nationwide 

Annual 

Secondary 

Emissions 

(tons/year)

tons per

eventd

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 flowback 

gas. Five percent of the remaining 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 Gas Star Program. Washington, DC. 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. 84-89 pp.

4 U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 Emissions 

from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 1990-2008. 

Washington, DC. 2010.

5. U.S Environmental Protection Agency. Methodology for Estimating CH4 and CO2 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. EPA600/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. EPA600/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. 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 Group, Inc. Preferred and Alternative Methods for Estimating Air Emissions 

from Oil and Gas Field Production and Processing Operation. Prepared for the U.S. 

Environmental Protection Agency. September 1999. 

19. New York State Department of Environmental Conservation. 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. Producers 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. 

14th 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 Implementation Workshop. Houston, TX. 2006. 

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

26. Memorandum to Bruce Moore from Heather Brown. Composition of Natural Gas for Use in the 

Oil and Natural Gas Sector Rulemaking. EC/R, Incorporated. June 29, 2011.
4-34

 

27 State 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/AQDOG11_Green%20Completion%20Application.pdf

28 Colorado Oil and Gas Conservation Commission. 2 CCR-404-1. http://oilgas.state.co.us/RuleMaking/FinalDraftRules/COGCCFinalDraftRules_110708.pdf

29. U.S. Environmental Protection Agency Fact Sheet No. 703: Green Completions. Office of Air 

and Radiation: Natural Gas Star Program. Washington, DC. September 2004.

30. Memorandum to Bruce Moore from Denise Grubert. American 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/n9190us3a.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 

CFR 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 CONTROLLERS

The natural gas industry uses a variety of process control devices to operate valves that regulate

pressure, flow, temperature, and liquid levels. Most instrumentation and control equipment falls into one 

of three categories: (1) pneumatic; (2) electrical; or (3) mechanical. Of these, only pneumatic devices are 

direct sources of air emissions. Pneumatic controllers are used throughout the oil and natural gas sector 

as part of the instrumentation to control the position of valves. This chapter describes pneumatic devices 

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 segment, an estimated 

400,000 pneumatic devices control and monitor gas and 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 monitor 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 controllers are automated instruments used for maintaining a process condition such as liquid 

level, pressure, pressure differential, and temperature. In many situations across all segments of the oil 

and gas industry, pneumatic controllers make use of the available high-pressure 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 the continuous 

release occurs is referred to as the bleed rate. Bleed rates are dependent on the design and operating 

characteristics of the device. Similar designs will have similar steady-state rates when operated under 

similar conditions. There are three basic designs: (1) continuous bleed devices are used to modulate 

flow, 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 recognized “closed loop” systems are applicable only 

in instances with very low pressure2and may not be suitable to replace many applications of bleeding 

pneumatic devices. Therefore, these devices are not further discussed in this analysis.

Snap-acting controllers are devices that only emit gas during actuation and do not have 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 an additional 

volume of gas during actuation, in addition to the device‟s bleed stream. Since actuation emissions serve 

the device‟s functional purpose and can be highly variable, the emissions characterized for high-bleed 

and low-bleed devices in this analysis (as described in section 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. Most applications (but not all), snapacting devices serve functionally different purposes than bleed devices. Therefore, snap-acting 

controllers are not further discussed in this analysis. 

In addition, not all pneumatic controllers are gas driven. At sites 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 release natural gas or VOC emissions. However, electrically powered 

systems have energy impacts, with associated secondary impacts related to generation of the electrical 

power required to drive the instrument air compressor system. Instrument air systems are feasible only at 

oil and natural gas locations where the devices can be driven by compressed instrument air systems and 

have electrical service sufficient to power an air compressor. This analysis assumes that natural gas 

processing plants are the only facilities in the oil and natural gas sector highly likely to have electrical 

service sufficient to power an instrument air system, and that most existing gas processing plants use 

instrument air instead of gas driven devices.9The application of 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, numerous 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 into two types based on their emissions rates: (1) highbleed 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 

devices 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 data 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 inquiries were made into 

the specifications of each device and whether it was applicable to oil and natural gas operations. Highbleed and low-bleed devices were differentiated using the 6 scfh threshold. 

Although by definition, a low-bleed device can emit up to 6 scfh, through this vendor research, it was 

determined that the typical low-bleed device available currently on the market emits lower than the 

maximum rate allocated for the device type. Specifically, low-bleed devices on the market today have 

emissions from 0.2 scfh up to 5 scfh. Similarly, the available bleed rates for a high bleed device vary 

significantly from venting as low as 7 scfh to as high as 100 scfh.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 States”. As described on page 2-16 of the report, “devices with emissions or „bleed‟ rates of 0.1 to 0.5 cubic feet per 

minute are considered to be „high-bleed‟ types (PG&E 1990).” This range of bleed rates is equivalent to 6 to 30 cubic feet per 

hour.

ii All rates 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 Gas 

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 STAR Program1

EPA 2000-

2010 X X
5-5

prevalence of each model type in the population of devices; which is an important factor in developing a 

representative emission factor. Therefore, for 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 gas 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 nongas driven controls. Therefore, to quantify representative emissions from a bleed-device in the natural 

gas processing segment, information from Volume 12 of the EPA/GRI reportiii was used to estimate the 

methane emissions from a single pneumatic device by type. 

The basic approach used for this analysis was to first approximate 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 methane 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 emissions 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.html
5-6

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 Productionb

6.91 1.92 0.073 0.26 0.072 0.003

Natural Gas Transmission and Storagec

3.20 0.089 0.003 0.24 0.007 0.0002

Oil Productiond

6.91 1.92 0.073 0.26 0.072 0.003

Natural Gas Processinge

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 emissions are derived from Table W-1A and W-1B of Subpart 

W. 

c. Natural gas transmission and 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. The number of facilities 

estimated in absence of regulation was undeterminable due to the magnitude of new sources estimated 

and the lack of sufficient data that could indicate the number of controllers that would be installed in 

states that may have regulations requiring low bleed controllers, such as in Wyoming and Colorado. 

For the natural gas production and oil production segments, the number of new pneumatics installed in a 

typical year was derived using a multiphase analysis. First, data from the US Greenhouse Gas Inventory: 

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 hydraulic 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 

Inventory 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 the 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 count 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 data found in the GRI study, where 51 percent of the pneumatic controllers are bleed devices in 

the production segment, and 32 percent of the pneumatic controllers are bleed devices 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 of 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 Yeara

Snap-Acting Bleed-Devices Total

Natural Gas and Oil Productionb16,371 17,040 33,411

Natural Gas Transmission and 

Storagec 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 

Greenhouse 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 fracturing, 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 

an average number of pneumatics being installed in this industry segment in a typical year. This 

analysis was performed using the Inventory of U.S. 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 related. 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, it 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 estimates 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 emissions 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 lowbleed device is the most likely scenario for 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, low-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 the 
5-10

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 1.9213 6.9112 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 emissions 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 transmission 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.

Low-bleed devices 

are, on average,

around $165 more 

than high bleed 

versions.

Convert to 

Instrument 

Air14

Compressed air may be substituted for natural gas in pneumatic 

systems without altering any of the parts of the pneumatic

control. In this type of system, atmospheric air is compressed, 

stored in a tank, filtered and then dried for instrument use. For 

utility purposes such as small pneumatic pumps, gas compressor 

motor starters, pneumatic tools and sand blasting, air would not 

need to be dried. Instrument air conversion requires additional 

equipment to properly compress and control the pressured air. 

This equipment includes a compressor, power source, air 

dehydrator and air storage vessel.

Replacing natural gas with instrument air in 

pneumatic controls eliminates VOC emissions 

from bleeding pneumatics. It is most effective 

at facilities where there are a high 

concentration of pneumatic control valves and 

an operator present. Since the systems are

powered by electric compressors, they require 

a constant source of electrical power or a backup natural gas pneumatic device. These 

systems can achieve 100 percent reduction in 

emissions. 

A complete cost 

analysis is provided 

in Section 5.4.2. 

System costs are

dependent on size of 

compressor, power 

supply needs, labor 

and other equipment. 

Mechanical 

and Solar 

Powered

Systems in 

place of Bleed 

device15

Mechanical controls operate using a simple design comprised of 

levers, hand wheels, springs and flow channels. The most 

common mechanical control device is the liquid-level float to 

the drain valve position with mechanical linkages. Electricity or 

small electrical motors (including solar powered) have been 

used to operate valves. Solar control systems are driven by solar 

power cells that actuate mechanical devices using electric 

power. As such, solar cells require some type of back-up power 

or storage to ensure reliability.

Application of mechanical controls is limited 

because the control must be located in close 

proximity to the process measurement. 

Mechanical systems are also incapable of 

handling larger flow fluctuations. Electric 

powered valves are only reliable with a 

constant supply of electricity. Overall, these 

options are applicable in niche areas but can 

achieve 100 percent reduction in emissions 

where applicable.

Depending on 

supply of power, 

costs can range from 

below $1,000 to 

$10,000 for entire 

systems.

Enhanced 

Maintenance16

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 

pneumatic 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

devices 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 systems 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 analysis. 

5.4.1 Low-Bleed Controllers

5.4.1.1 Emission Reduction Potential

As discussed in the above sections, low-bleed devices provide the same functional control as a highbleed device, but have lower continuous bleed emissions. As summarized in Table 5-6, it 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 current 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 isolation valve is involved. Based on criteria provided by the Natural Gas STAR Program, it is 

assumed about 80 percent of high-bleed devices can be replaced with low-bleed devices throughout the 

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 segment (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 HighBleed 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 and discharge pressure and 

actuate a re-cycle when one or the other is out of the specified target range. Other scenarios for fast and

precise control include transient (non-steady) situations where a gas flow rate may fluctuate widely or 

unpredictably. This situation requires a responsive high-bleed device to ensure that the gas flow can be 

controlled in all situations. Temperature and level controllers are typically present in control situations 

that are not prone to fluctuate as widely or where the fluctuation can be readily and safely 

accommodated by the equipment. Therefore, such processes can accommodate control from a low-bleed 

device, which is slower-acting and less precise.

Safety concerns may be a limitation issue, but only in specific situations because emergency 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 control 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 pneumatic gas supply will be lost. For this reason, control valves are 

deliberately selected to either fail open or fail closed, depending on which option is the failsafe.

5.4.1.2 Cost Impacts

As described in Section 5.2.2, costs 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.vThus, 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 incremental 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 Devicesa

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. Assuming production quality gas is 82.8 percent methane by 

volume, this equals 385.5 Mcf natural gas recovered per year. Therefore, the value of recovered natural 

gas from one pneumatic device in the production segment equates to approximately $1,500. Savings 

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 needed. 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 source, 

dehydrator, and volume tank. The following is a description of each component as described in the 

Natural Gas STAR document, Lessons Learned: Convert Gas Pneumatic Controls to Instrument Air:

 Compressors used for instrument air delivery are available in various types and sizes, from 

centrifugal (rotary screw) compressors to reciprocating piston (positive displacement) types. 

The size of the compressor depends on the size of the facility, the number of control devices 

operated by the system, and the typical bleed rates of these devices. The compressor is usually 

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

 

vi 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 value, a conservative savings of $4.00 per Mcf 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 existing electric power 

supply or have their own power generation system. For smaller facilities and in remote 

locations, however, a reliable source of electric power can be difficult to assure. In some 

instances, solar-powered battery-operated air compressors can be cost effective for remote 

locations, which reduce both 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 controller orifices. 

 The volume tank holds enough air to allow the pneumatic control system to have an 

uninterrupted supply of high pressure air without having to run the air compressor 

continuously. The volume tank allows a large withdrawal of compressed air for a short time, 

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 control. 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 use 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 consistent 
5-19

supply of electrical power. Instrument air systems are also usually 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. The size of the compressor will depend on the number of control loops present at a location. A 

control loop consists of one pneumatic controller and one control valve. The volume of compressed air 

supply for the pneumatic system is equivalent to the volume of gas used to run the existing 

instrumentation – adjusted for air losses during the drying process. The current volume of gas usage can 

be determined by direct metering if a meter is installed. Otherwise, an alternative rule of thumb for 

sizing instrument air systems is one cubic foot per minute (cfm) of instrument air for each control loop.14

As the system is powered by electric compressors, the system requires a constant source of electrical 

power or a back-up pneumatic 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 instrument 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 system can 

provide and not on a per device basis. This approach was chosen because we assume new processing 

plants will need to provide instrumentation of multiple control loops and size the instrument air system 

accordingly. We also assume that existing processing plants have already upgraded to instrument air 

 

vii Costs have been converted to 2008 US dollars using the Chemical Engineering Cost Index. 
5-20

Table 5-9. Compressor Power Requirements and Costs for Various Sized Instrument Air 

Systemsa

Compressor Power Requirementsb 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 Air14

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 Capital and Annual Costs of Various Sized Representative Instrument Air Systems

Instrument 

Air System 

Size

Compressor Tank Air Dryer Total 

Capitala

Annualized 

Capitalb

Labor 

Cost

Total 

Annual 

Costsc

Annualized Cost 

of Instrument Air 

System

Small $3,772 $754 $2,262 $16,972 $2,416 $1,334 $8,674 $11,090

Medium $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 compressors, tank, an air dryer and installation. Installation costs are assumed to be equal to 1.5 

times the cost of capital. Equipment costs were derived from the 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 cost 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 sizes of representative instrument air systems.

5.4.2.4 Secondary Impacts

The secondary impacts from instrument air systems are indirect, variable and dependent on the electrical 

supply used to power the compressor. No other secondary impacts are expected. 

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 Source Performance Standard 

(NSPS) at the time of installation. The following Regulatory alternatives were evaluated:

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

 Regulatory Option 2: Establish an emissions limit equal to 6 scfh.

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 effective for natural gas processing plants as 

summarized in Table 5-11. A major assumption of this analysis, however, is that processing plants 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 chosen method of meeting the requirement. In the key instances related to pressure 

control that would disallow the use of a low-bleed device, specific monitoring and recordkeeping criteria 
5-23

Table 5-11 Cost-effectiveness of Representative Instrument Air Systems in the Natural Gas Processing Segment

System 

Size

Number of 

Control 

Loops

Annual Emissions 

Reductiona(tons/year) Value of

Product 

Recovered

($/year)b

Annualized Cost of 

System

VOC Costeffectiveness ($/ton)Methane Costeffectiveness ($/ton)

VOC CH4 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 assumes natural gas processing is 82.8 percent methane by volume. A natural gas price of $4 per Mcf was 

assumed. 
5-24

would be required to ensure the device function dictates the precision of a high bleed device. Therefore, 

Regulatory Option 2 was accepted for locations outside of natural gas processing plants. 

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 processing 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 costs 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

Table 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 Emission 

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

Regulatory Option 2 (emission threshold equal to 6 scfh)

Oil and 

Natural Gas 

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

Minor 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 represent 

the number of new devices expected per year reduced by 20 percent. This is consistent 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 these 

segments. For the natural gas processing segment the number of new sources represents 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 bleed device versus a new high bleed device. The 

capital cost of the IAS is based on the small 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 

industry 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 Star. 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. Methodology 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 CH4 and CO2 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. EPA600/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. EPA600/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. 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. 

13 Memorandum to Bruce Moore from Heather Brown. Gas Composition Methodology. July 2011
5-27

 

14 U.S. Environmental Protection Agency. Lessons Learned: Convert Gas Pneumatic Controls to 

Instrument Air. Office of Air and Radiation: Natural Gas Star. Washington, DC. February 2004

15 U.S. Environmental Protection Agency. Pro Fact Sheet No. 301. Convert Pneumatics to 

Mechanical Controls. Office of Air and Radiation: Natural Gas Star. Washington, DC. 

September 2004.

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 Administration. Annual U.S. Natural Gas Wellhead Price. Energy 

Information Administration. Natural Gas Navigator. Retrieved online on 12 Dec 2010 at 

<http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm>
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, through the supply chain, and to the consumer. The types of 

compressors that are used by the oil and gas industry as prime movers are reciprocating and centrifugal 

compressors. This chapter discusses the air pollutant emissions from these compressors and provides 

emission estimates for reducing emission from these types of compressors. In addition, nationwide 

emissions estimates from new sources are estimated. Options for controlling pollutant emissions from 

these compressors are presented, along with costs, emission reductions, and secondary impacts. Finally, 

this chapter discusses considerations in developing regulatory alternatives for both reciprocating and 

centrifugal compressors.

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 cylinder where it is compressed by a piston driven in a reciprocating motion by the 

crankshaft powered by an internal combustion engine. Emissions occur when natural gas leaks around 

the piston rod when pressurized natural gas is in the cylinder. The compressor rod packing system 

consists of a series of flexible rings that create a seal around the piston rod to prevent gas from escaping 

between the rod and the inboard cylinder head. However, over time,during operation of the compressor, 

the rings become worn and the packing system will need to be replaced to prevent excessive leaking 

from the compression cylinder. 

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. The circulated oil entrains and absorbs some compressed natural gas which is released to the 
6-2

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 forcescreate a thin gap of high pressure gas between 

the rings through which little gas can leak. The rings do not wear or need lubrication because they are 

not in contact with each other. Therefore, operation and maintenance costs are 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 that 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 methodology for estimating emission from reciprocating compressor rod packing was to use the 

methane emission factors referenced in the EPA/GRI study1and use the methane to pollutant ratios 

developed in the gas composition memorandum.2The emission factors in the EPA/GRI document were 

expressed in thousand standard cubic feet per cylinder (Mscf/cyl), and were multiplied by the average 

number of cylinder per reciprocating compressor at each oil and gas industry segment. The volumetric 

methane emission rate was converted to a mass emission rate using a density of 41.63 pounds of 

methane per thousand cubic feet. This conversion factor was developed assuming that methane is an 

ideal gas and using the ideal gas law to calculate the density. A summary of the methane emission 

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 the
6-3

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: 

1990-20081

EPA 2010 Nationwide X

Greenhouse Gas Mandatory 

Reporting Rule and 

Technical Supporting 

Document2

EPA 2010 Nationwide X

Methane Emissions from 

the Natural Gas Industry3

Gas Research 

Institute/EPA 1996 Nationwide X

Natural Gas STAR 

Program4,5 EPA 1993-2010 Nationwide X X
6-4

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 

hour/year 

Compressor 

Pressurized)

Wet Seal 

Methane 

Emission 

Factor 

(scf/minute)

Dry Seals 

Methane 

Emission 

Factor 

(scf/minute)

Production 

(Well Pads) 0.271a

4 100% N/Af N/Af

Gathering & 

Boosting 25.9b

3.3 79.1% N/Af N/Af

Processing 57c2.5 89.7% 47.7g6

g

Transmission 57d3.3 79.1% 47.7g6

g

Storage 51e4.5 67.5% 47.7g6

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. EPA/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). “Methane Emissions from the Natural Gas Industry: Volume 8 – Equipment 

Leaks.” Table 4-24. 

f. The 1996 EPA/GRI Study Volume 113, does not report any centrifugal compressors in the 

production or gathering/boosting sectors, therefore no emission factor data were published 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 0.0131
6-6

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 number 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 whenever 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 information 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 

estimates 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 compressor 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 subpart W comment period from nine basins supplied by the El Paso Corporation,

8

the 
6-7

Table 6-4.Approximate Number 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 4
6-8

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® database9between 2007 and 2008, which came to 68,000 new well 

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 operates 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 compressors 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 compressors 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 for 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 

compressors 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 using the 

differences in the greenhouse gas inventory12,13 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 

2008, 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

The 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 . For 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 increase 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 centrifugal 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 for 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

Centrifugal Compressors

Processing 3,640 329 11.8

Transmission/Storage 1,768 48.9 1.45
6-11

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 

includesreplacement of the compressor rod packing, replacement of the piston rod, and the refitting or 

realignment of the piston rod. 

The replacement of the rod packing is a maintenance task performed on reciprocating compressors to 

reduce the leakage of natural gas past the piston rod. Over time the packing rings wear and allow more 

natural gas to escape around the piston rod. Regular replacement of these rings reduces 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 therefore the 

tightness of the seal) and the rate of ring wear. An out-of-round shaft not only seals poorly, allowing 

more leakage, but also causes uneven wear on the seals, thereby shortening the life of the piston rod and 

the packing seal. Replacing or upgrading the rod can reduce reciprocating compressor rod packing 

emissions. Also, upgrading piston rods by coating them with tungsten carbide or chrome reduces wear 

over the life of the rod. This analysis assumes operators will choose, at their discretion, when to replace 

the rod and hence, does not consider this control technique to be a practical control option for 

reciprocating compressors. A summary of these techniques are presented in the following sections.

Potential control options to reduce emissions from centrifugal compressors include control techniques 

that limit the leaking of natural gas across the rotating shaft, or capture and destruction of the emissions 

using a flare. A summary of these techniques are presented in the following sections.

A control technique for limiting or reducing the emission from the rotating shaft of a centrifugal 

compressor is a mechanical dry seal system. This control technique uses rings to prevent the escape of 

natural gas across the rotating shaft. This control technique was determined to be a viable option for 

reducing emission from centrifugal compressors.
6-12

For centrifugal compressors equipped with wet seals, a flare was considered to be a reasonable option 

for reducing emissions from centrifugal compressors. Centrifugal compressors require seals around the 

rotating shaft to prevent natural gas from escaping where the shaft exits the compressor casing. “Beam” 

type compressors have two seals, one on each end of the compressor, while “over-hung” compressors 

have a seal on only the “inboard” (motor end) side. These seals use oil, which is circulated under high 

pressure between three rings around the compressor shaft, forming a barrier against the compressed gas 

leakage. The center ring is attached to the rotating shaft, while the two rings on each side are stationary 

in the seal housing, pressed against a thin film of oil flowing between the rings to both lubricate and act 

as a leak barrier. The seal also includes “O-ring” rubber seals, which prevent leakage around the 

stationary rings. The oil barrier allows some gas to escape from the seal, but considerably more gas is 

entrained and absorbed in the oil under the high pressures at the “inboard” (compressor side) seal oil/gas 

interface, thus contaminating the seal oil. Seal oil is purged of the absorbed gas (using heaters, flash 

tanks, and degassing techniques) and recirculated back to the seal. As a control measure, the recovered 

gas would then be sent to a flare or other combustion device. 

6.4.2 Reciprocating Compressor 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 

rod packing emissions. Rod packing emissions typically occur around the rings from slight movement of 

the rings in the cups as the rod moves, but can also occur through the “nose gasket” around the packing 

case, between the packing cups, and between the rings and shaft. If the fit between the rod packing rings 

and rod is too loose, more compressed gas will escape. Periodically replacing the packing rings ensures 

the correct fit is maintained between packing rings and the rod. 

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 emissionswith the average emissions from newly installed and wornin 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 gathering 
6-13

and boosting compressors and not wellhead compressor which are known to be smaller. The calculation 

for gathering and boosting reductions is shown in Equation 1.

 

6

&

&

&

10

   8760



Comp E E C O

R

G B New

G B

G B New

WP

Equation 1

where,

G B RWP& = Potential methane emission reductions from gathering and boosting compressors 

switching from wet seals to dry seals, in million cubic feet per year (MMcf/year);

G B CompNew& = Number of new gathering and boosting compressors;

EG&B = Methane emission factor for gathering and boosting compressors inTable 6-2, in cubic 

feet per hour per cylinder;

ENew=Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per 

hour per cylinder15 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;

106 = 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 installed rod packing to determine methane emission reductions. The calculation for wellhead 

compressor reductions is shown in Equation 2 below.

 















    



Trans

Well Trans New

Well

New

Well E

Comp E C O E E

R 6

10

8760

Equation 2

where,

RWell= Potential methane emission reductions from wellhead compressors switching from wet 

seals to dry seals, in million cubic feet per year (MMcf/year);

Well CompNew = Number of new wellhead compressors;

EWell = Methane emission factor for wellhead compressors from Table 6-2, cubic feet per hour 

per cylinder;

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

ETrans = Methane emissions factor for transmission compressors from Table 6-2 in cubic feet per 

hour per cylinder;

ENew = Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per 

hour per cylinder16 for this analysis;

8760 = Number of days in a year;

106 = Number of cubic feet in a million cubic feet.

The 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 average emission factor from newly installed 

rod packing. This calculation, shown in the Equation 3 below, was performed for each of the natural gas 

processing, transmission, and storage/LNG sectors.

 

6

&

10

   8760



Comp E E C O

R

G B New

PTS

New

PTS

Equation 3

where,

RPTS = 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);

PTS CompNew = Number of new processing, transmission, or storage compressors;

EG&B = Methane emission factor for processing, transmission, or storage compressors in Table 6-

2, in cubic feet per hour per cylinder;

ENew=Average emissions from a newly installed rod packing, assumed to be 11.5 cubic feet per 

hour per cylinder17 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;

106 = Number of cubic feet in a million cubic feet.

A summary of the potential emission reductions for reciprocating rod packing replacement for each 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 composition18 for each of the segments. 

Reciprocating compressors in the processing sector were 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 Compressor Emission Reductions 

(tons/compressor-year)

Nationwide Emission Reductions

(tons/year)

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 0.0718
6-16

6.4.2.3 Cost Impacts

Costs for the replacement of reciprocating compressor rod packing were obtained from a Natural Gas 

Star Lessons Learned document19 which estimated the cost to replace the packing rings to be $1,620 per 

cylinder. It was assumed that rod packing replacement would occur during planned shutdowns and 

maintenance and therefore, no travel costs will be incurred for implementing the rod packing 

replacement program. In addition, no costs were included for monitoring becausethe rod 

packingplacement 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 arebased on the replacement of 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 pressurized 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 hours. 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 operating 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 an 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.

Monetary savings associated with the amount of gas saved with reciprocating compressor rod packing 

replacement was estimated using a natural gas price of $4.00 per Mcf.21 This cost was used to calculate 

theannual cost with gas savings using the methane emission 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 

benefits for transmission and storage facilities, because they do not own the natural gas that is
6-17

Table 6-7. Cost Effectiveness for Reciprocating Compressor Rod Packing Replacement

Oil and Gas 

Segment

Capital Cost 

($2008)

Annual Cost per Compressor 

($/compressor-year) VOC Cost Effectiveness ($/ton) Methane Cost Effectiveness ($/ton)

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/A
6-18

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 

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

6.4.3 Centrifugal Compressor Dry Seals

6.4.3.1 Description

Centrifugal compressor dry seals operate mechanically under the opposing force created by 

hydrodynamic grooves and springs. The hydrodynamic grooves are etched into the surface of the 

rotating ring affixed to the compressor shaft. When the compressor is not rotating, the stationary ring in 

the seal housing is pressed against the rotating ring by springs. When the compressor shaft rotates at 

high speed, compressed gas has only one pathway to leak down the shaft, and that is between the 

rotating and stationary rings. This gas is pumped between the rings by grooves in the rotating ring. The 

opposing force of high-pressure gas pumped between the rings and springs trying to push the rings 

together creates a very thin gap between the rings through which little gas can leak. While the 

compressor is operating, the rings are not in contact with each other, and therefore, do not wear or need 

lubrication. O-rings seal the stationary rings in the seal case. 

Dry seals substantially reduce methane emissions. At the same time, they significantly 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 6scfmmethane 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 pumps 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 seals 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 not have moving parts associated with oil circulation (e.g., pumps, control valves, relief 

valves, and the seal oil cost itself).

 Elimination of Oil Leakage from Wet Seals. Substituting dry seals for wet seals eliminates seal 

oil leakage into the pipeline, thus avoiding contamination of the gas and degradation of the 

pipeline.

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 would 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 centrifugal 

compressors and 24.2 percent for transmission centrifugal compressors. The operating factors are used 

to account for the percent of time in a year that a compressor is in the operating mode. The operating 

factors 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 seal centrifugal compressors. The dry seal 

emission factor is based on information from the Natural Gas STAR Program.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 centrifugal compressor with dry seals cost between $50,000 and $100,000 more 

than the same centrifugal compressor with wet seals. However, this price difference is only about 1 to 3 
6-20

Table 6-8. Estimated Annual Centrifugal Compressor Emission Reductions from Replacing Wet Seals with Dry Seals

Oil & Gas Segment

Number of 

New Sources 

Per Year

Individual Compressor Emission Reductions

(ton/compressor-year)

Nationwide Emission Reductions

(ton/year)

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 1.27
6-21

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 capital cost for a dry seal compressor is $75,000. The annual cost was 

calculatedas 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 compressors 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 Table 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 and storage facilities, because it is assumed the owners of the 

compressor station may not own the natural 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, and 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 circulated under high pressure between three rings 

aroundthe compressor shaft, forming a barrier against the compressed gas. The center ring is attached to 

the rotating shaft, while the two rings on each side are stationary in the seal housing, pressed against a 

thin film of oil flowing between the rings to both lubricate and act as a leak barrier. Compressed gas 

becomes absorbed and entrained in the fluid barrier and is removed using a heater, flash tank, or other 

degassing technique so that the oil can be recirculated back to the wet seal. The removed gas is either 
6-22

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 

($/ton)

Methane Cost Effectiveness 

($/ton)

without 

savings

with O&M 

and gas 

savings

without

savings

with O&M 

and gas 

savings

without 

savings

with O&M and 

gas savings

Processing $75,000 $10,678 -$123,730 $595 -$6,892 $54 -$622

Transmission/Storage $75,000 $10,678 -$77,622 $3,495 -$25,405 $97 -$703
6-23

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 that 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 calculate 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. The combustion of the 

recovered gas creates secondary emissions of hydrocarbons, nitrogen oxide (NOX), carbon dioxide 

(CO2), and carbon monoxide (CO) emissions. A summary of the estimated secondary emission are 

presented in Table 6-11. No other wastes should 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 

thedriveshaft. A centrifugal compressor is defined as a piece of equipment that compresses a process gas 

by means of mechanical rotating vanes or impellers. Therefore these types of compressor would be
6-24

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 

(tons/compressor-year)

Nationwide Emission Reductions

(tons/year)

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 44.2 1.31
6-25

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 Negligible
6-26

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-year)

VOC Cost Effectiveness 

($/ton)

Methane Cost Effectiveness 

($/ton)

without 

savings

with gas 

savings without savings with gas savings

without 

savings

with gas 

savings

Processing $67,918 $103,371 N/A $5,299 N/A $478 N/A

Transmission/Storage $67,918 $103,371 N/A $31,133 N/A $862 N/A
6-27

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 

on26,000 hours of operation while the compressor is pressurized.

 Regulatory Option 2: Require all centrifugal compressors to be equipped with dry seals.

 Regulatory Option 3: Require centrifugal compressors equipped with a wet seal to route the 

recovered gas emissions to a combustion device.

6.5.1 Evaluation of Regulatory Options

The first regulatory option for replacement of the reciprocating compressor rod packing based on the 

number of hours that the compressor operates in the pressurized mode was described in Section 6.4.1. 

The VOC cost effectiveness from $56,847 for reciprocating compressors located at production pads to 

$273 for reciprocating compressors located at 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, 

gathering 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 at 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 

company were equipped with dry seals. Another vendor confirmed in 2010 that the rate at which new 

compressor sales have dry seals is still 90 percent; thus, it was assumed that from 2003 onward, 

90 percent of new compressors are equipped with dry seals. The VOC 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 regulatory 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 seals 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 these 
6-28

pressures. Therefore, it does not appear that any facilities would be required to operate a centrifugal 

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 Nationwide 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 compressors 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 and 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 summary 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 Regulatory 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

savings ($/yr)

Annual Cost 

with savings 

($/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 $104,247 $32,547 $32,547

Storage 4 2.42 87.3 0.0718 $29,160 $9,104 $9,104
6-30

Table 6-14. Nationwide Cost Impacts for Regulatory Option 2

Oil & Gas Segment

Number of 

New Sources 

Per Year

Nationwide Emission Reductions1

(tons/year) Total Nationwide Costsa

VOC Methane HAP Capital Cost 

($)

Annual Cost 

w/o Savings 

($/year)

Annual Cost 

w/ Savings 

($/year)

Production (Well Pads) 0 0 0 0 0 0 0

Gathering & Boosting 0 0 0 0 0 0 0

Processing 16 118 422 4.42 $100,196 $14,266 -$120,144

Transmission/Storage 14 3.24 117 0.0962 $50,098 $7,133 -$37,017

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.EPA600/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. Environmental 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. Washington, 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 Greenhouse 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 Natural 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. Greenhouse 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. April 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.
6-32

 

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. Environmental 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 

Packing 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 Learned: 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. Retrieved 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 Conference 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 Petroleum Systems. Greenhouse Gas Inventory: Emission and 

Sinks1990-2009. Washington, DC. April 2011. Annex 3. Page A153.http://epa.gov/climatechange/emissions/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 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.EPA600/R-96-080h. June 1996.

27 EPA (2006).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 emission 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 alternatives 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 

solution. 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 through either a two phase separator 

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

(where the associated gas is removed and the oil and water are also separated). At the separator, low 

pressure gas is physically separated from the high pressure oil. The remaining low pressure oil is then

directedto 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 vapors in the storage vessels. Storage 

vessels are typically installed with similar or identical vessels in a group, referred to in the industry as a 

tank battery.

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

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

filling of storage vessels. Breathing losses are the release of gas associated with daily temperature 

fluctuations and other equilibrium effects. Flash losses occur when a liquid with entrained gases is 

transferred from a vessel with higher pressure to a vessel with lower pressure, thus allowing entrained 

gases or a portion of the liquid to vaporize or flash. In the oil and natural gas production segment, 

flashing losses occur when live crude oils or condensates flow into a storage vesselfrom a processing 

vessel operated at a higher pressure. Typically, the larger the pressure drop, the more flash emissions

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 vesselwill 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 Emissions 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 attank batteries throughout the 

sector. Model tank batteries were not intended to represent any single facility, 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, subpart HH), model plants were developed to represent 

condensate tank batteries across the industry.1For this current analysis, the most recent inventory data 

available was the 2008 U.S. Greenhouse Gas Emissions Inventory.2,3Therefore, 2008 was chosen to 

represent 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 scaled
7-3

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 

Tanks4

Texas Environmental 

Research Consortium 2009 Regional X X

Lessons Learned from Natural Gas STAR 

Partners:Installing Vapor Recovery Units on 

Crude Oil Storage Tanks5

EPA 2003 National X

Upstream Oil and Gas Storage Tank Project Flash 

Emissions Models Evaluation – Final Report6

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 TANKS8 American Petroleum 

Institute National X

Inventory of U.S. Greenhouse Gas Emissions and 

Sinks2,3EPA

2008 

and 

2009

National X
7-4

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 each 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 106 million barrels per year (MMbbl/yr) in 1992to 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. The model condensate tank batteries are 

presented in Table 7-2. 

7.2.2.2 Model Crude Oil Tank Batteries

According to the Natural Gas STAR program,5there were 573,000 crude oil storage tanksin 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 decrease 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 519,161 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 tanks across the four model crude oil tank battery 

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 the modelcondensate and crude oil tank battery distributionswere 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, throughput, 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 industry representatives, this 
7-5

Table 7-2. Model Condensate Tank Batteries

Model Condensate Tank Battery

Parameter E F G H

Condensate throughput (bbl/day)a15 100 1,000 5,000

Condensate throughput (bbl/yr) a5,475 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)a12,000 500 100 70

Estimated tank battery population (2008) b14,038 585 117 82

Total number of storage vessels (2008) b56,151 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 batterya26% 7% 15% 51%

Total tank battery condensate throughput (MMbbl/yr)c32.8 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 (References2,3).

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 rangea 94.7% 3.95% 0.789% 0.552%

Number of storage vesselsb491,707 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 vessels (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 vesselsprovided with the E&P TANKS program, 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 

emissionswas studied. While many 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 degrees as a parameter to 

distinguish between lower emitting storage vessels 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 the 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.

iiAn average emission factor was developed for each type of liquid. The average 

of condensate 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 that 

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

Parametera

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)c2.0 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 expected 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 be 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 with increases in production. The Energy 

Information Administration (EIA), published crude oil production rates up to the year 2011.10Therefore, 

using the forecast function in Microsoft Excel® , crude oil production was predicted for the year 2015.iii

From 2009 to 2015,iv the expected growth 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 previously, 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. To more accurately 

estimate baseline emissions 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 therefore 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 regulationb 1,688 70 14 10 1,782

Uncontrolled VOC Emissions from storage vessel 

at model tank batteryc 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 regulationb 14,782 616 123 86 15,607

Uncontrolled VOC Emissions from storage vessel 

at model tank batteryc 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 vessel 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 and 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 vessels 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 federal 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 vessels. The other option would be to route the 

emissions from the storage vessels 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 Description

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 typically 
7-13

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 gathering 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 feasibility 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 vessels causing 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.Cost information contained in the EIA was 

assumed to be giving in 2007 dollars.7Therefore 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 cost 

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., 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 impacts 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 Itema

Capital 

Costs

($)

NonRecurring, 

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 onetime 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 

hydrocarbons, found in waste streams.13 Combustors are used to control VOC in many industrial 

settings, since thecombustorcan normally handle fluctuations in concentration, flow rate, heating value, 

and inert species content.14 For this analysis, the types of combustors 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 obtained 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, including 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 presented 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. Reliable data 

for emission factors from combustors on condensate and crude oil storage vessels 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 thebest indication 

for secondary pollutants from combustors currently available. The secondary emissionsper storage 

vessel are provided in Table 7-9.
7-16

Table 7-8. Total Capital Investment and Total Annual Cost of a Combustor

Cost Itema

Capital 

Costs

($)

NonRecurring, 

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 Systemd$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 onetime 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 not 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

CO2 60 Kg/MMBtub5.62

NOX 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. CO2 emission factor obtained from 40 CFR Part 98, subpart Y, Equation Y-2.
7-18

7.5 Regulatory Options and Nationwide Impacts of Regulatory Options

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 the liquid as it enters the atmospheric 

pressure storage vessel, the liquid’s volatility and temperature of the liquid.Some storage vessels have 

negligible emissions, such as those with very little throughput and/or handling heavy liquids entering at 

atmospheric pressure. Therefore, in order to determine the most cost effective means of controlling 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 emissions 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 controlling 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 combustoris 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 combustorbecause a combustordestroys, rather than recycles, valuable resources 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 Consortium15 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 factor 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 

unitsd

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 option. 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 Option 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 percent, 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 vessels with a throughput greater than 1 bbl/day 

(equivalent emissions of 0.3 tons/year);

 Regulatory Option 2: Control condensate storage vessels with a throughput greater than 5 

bbl/day (equivalent emissions of 1.5 tons/year);

 Regulatory Option 3: Control condensate storage vessels with a throughput greater than 20 

bbl/day (equivalent emissions of 6 tons/year);

 Regulatory Option 1: Control condensate storage vessels with a throughput greater than 50 

bbl/day (equivalent emissions of 15 tons/year);

As shown in Table 7-11, Regulatory Options 1 and 2 are not cost effective crude oil storage vessels 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 Option 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 impacts, the populations of new and modified crude oil storage vessels associated with 

categories G 
7-21

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 

unitsd

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 

greater 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 primary 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 options 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 (Crude 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 Tables7-10 and 7-11. It 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 vessels 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 

reductions 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 

Battery

Number of 

Sources 

subject to 

Regulatory 

Optiona

VOC 

Emissions 

for a 

Typical 

Storage 

Vessel

(tons/year)

Capital 

Cost 

forTypi

cal 

Storage 

Vesselb

($)

Annual Cost for a 

Typical Storage 

Vesselb

($/yr)

Nationwide Emission 

Reductions 

(tons/year)

c

VOC Cost Effectiveness 

($/ton)

Methane Cost 

Effectiveness 

($/ton)

Total Nationwide Costs

(million $/year)

without

savings

with

savings VOC Methaned withoutsavings

with

savings

without

savings

with

savings

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 Impactse

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 operational difficulties of using a VRU. Capital and Annual Costs determined using the 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 storage 

vessel multiplied by the number of sources subject to the regulatory option.

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 storage 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 Section 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 average 

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 typical 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 regulatory 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 estimated 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 average 

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

Regulatory 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 for controlling a single storage vessel 

using a combustor are presented in Table 7-9. Nationwide secondary impacts are calculated by 
7-25

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

CO2 5.62 854

NOX 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 Table 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), Nunn, 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. Environmental 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. Production 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=9
7-27

11. Memorandum from Wilson, D., et al, ERG, to A. Pope, U.S. Environmental Protection 

Agency.Documentation for NEI Updates for Oil and Natural 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 Industrial 

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 emissions 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 connections 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 subsections 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 emissions 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, especially 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.1,2,3In 

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 combinations of process equipment and 

components. This is particularly true in the production segment of the industry, where “surface sites” 

can vary from sites where only a wellhead and associated piping is located to sites where a substantial 

amount of separation, treatment, and compression occurs. In order to conduct analyses to be used in 

evaluating potential options to reduce emissions from leaking equipment, a model plant approach was 

used. The following sections discuss the creation of these model plants.

Information 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 model 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 equipment counts are consistent with those contained in EPA’s analysis to estimate methane 

emissions conducted in support of the Greenhouse Gas Mandatory Reporting Rule (subpart W), which 

was published in the Federal Register on November 30, 2010 (75 FR 74458), These 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. 

These 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 wellhead 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 leaks 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: 1990-20084

EPA 2010 Nationwide X

Methane Emissions from the 

Natural Gas Industry567

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 State12

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 Data15

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 Estimates17

EPA 1995 Nationwide X X
8-4

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 equipment.4The type of production equipment located 

at a well pad include: gas wellheads, separators, meters/piping, gathering compressors, heaters, and 

dehydrators. The types of components that are associated with this equipment include: valves, 

connectors, open-ended lines, and pressure relief valves. Four model 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 of 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 can 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 Table 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/GRIdocument. The 

components for gathering compressors were included in the model plant total counts, but the compressor 

seals were excluded. Compressors seals are addressed in a Chapter 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 Plants

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 Production 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

Equipment 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 both. The types of process equipment used to separate the 

liquids are separators, glycol dehydrators, and amine treaters. In addition, centrifugal and/or 

reciprocating compressors are used to pressurize and move the gas from the processing facility to the 

transmission 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 

included 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 in 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.5Annual 

emissions were calculated assuming 8,760 hours of operation each year. The emissions factors are 

provided for total organic compounds (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 presented in 
8-10

Table 8-6.Average Component Count for Oil and Gas Processing 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 baseline 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 Energy 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 converted 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 average number of 

compressors in the gas production section. It was assumed that this average of 4.5 compressors for gas 

production facilities is applicable to gathering and boosting stations. Therefore, using the inventory of 

32,233 compressors and the average 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 estimate the number of 

new gathering and boosting stations. This provided an estimate of 275 new gathering and boosting 
8-14

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 4-17, 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 0.0806
8-16

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 facilities was estimated using gas processing data from the Oil and Gas 

Journal. The Oil and Gas Journal Construction Survey 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 throughput 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 

EIApredicts a 1.03 tcf/year increase in natural gas processing from 21.07 to22.104 tcf/year. This would 

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 processing 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 estimates 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 

(tons/yr)

Methane 

Emissions 

(tons/yr)

VOC 

Emissions 

(tons/yr)

HAP 

Emissions 

(tons/yr)

Well Pads

1 605 292 203 56.3 2.12

2 2,610 34,687 24,116 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

2 187 9,513 6,618 1,835 69.2

3 44 3,106 2,160 598 22.6

Total 275 13,931 9,690 2,687 101

Processing 1 29 2,146 1,490 415 15.6

Transmission/Storage 1 107 11,567 10,497 290 8.62
8-18

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 emissions 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 due to normal wear or 

improper maintenance. A leak is detected whenever the measured concentration exceeds the threshold 

standard (i.e., leak definition) for the applicable regulation. Leak definitions vary by regulation, 

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 

inspections 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 detect 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 such 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 infrared frequency range. In this range, hydrocarbons absorb the infrared light and are revealed as a 

dark image or cloud on the camera. The passive infrared cameras scan an area to produce images of 

equipment leaks from a number of sources. Active infrared cameras point or aim an infrared beam at a 

potential source to indicate the presence of equipment leaks. The optical imaging camera 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, and component type can be correlated into leak rate by using 

algorithms developed by the instrument manufacturer. The acoustic detector does not decrease the 

monitoring time because components are measured separately, like the OVA or TVA monitoring. The 

accuracy of the measurements using the acoustic detector can also be questioned due to the number of 

variables used to determine the equipment leak emissions.

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 inspections 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 packing.

Once 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 maintained 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 an 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 valves 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 an

OVA or TVA (10,000 ppm leak definition), monthly monitoring of valves (500 ppm leak definition) and 

requires open-ended lines and pressure relief devices to operate with no detectable emissions (500 ppm 

leak definition). The 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 thirdoption that was investigated was the implementation of a LDAR program using an optical gas 

imaging system. This option is currently available as an alternative work practice (40 CFR Part 60, 

subpart A) for monitoring emissions from equipment leaks in subpart VVa. The alternative work 

practice requires monthly monitoring of all components using the optical gas imaging system and an 
8-21

annual monitoring of all 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 Aalternative 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 connectors. These components are 

monitored with an OVA or TVA to determine if a component is leaking and measure the concentration 

of the organics if the component is leaking. Connectors, valves, and pressure relief devices have a leak 

definition of 500 parts 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 detectable 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 each 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, monthly monitoring provides higher 

control effectiveness than quarterly 
8-22

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 

Definitiona

Chemical Process Unit

Valves – Gas Serviceb87 67 92

Valves – Light Liquid Servicec84 61 88

Pumps – Light Liquid Servicec 69 45 75

Connectors – All Services --- --- 93

Petroleum Refinery

Valves – Gas Serviceb88 70 96

Valves – Light Liquid Servicec76 61 95

Pumps – Light Liquid Servicec68 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 subject 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 surface of a 

leak source that indicates that a VOC emission (leak) is present. The leak definition is an 

instrument meter reading based on a reference compound. Decreasing the leak definition 

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.7This leak fraction is used in a steady state set of 

equations to determine the final leak rate after implementing a LDAR program.8The initial leak rate and 

the final leak rate after implementing a LDAR program were then used 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 for pressure relief devices. 

8.4.2.3 Cost Impacts

Costs were calculated using a LDAR cost spreadsheet developedfor 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 openended 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 lines.

 A wage rate of $30.46 per hour was used to determine labor costs for repair.
8-24

 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 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 monitor 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 facility 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 get 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 using 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 month, 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 performed for each of the oil and gas sectors using the 

component count for an average size facility. This Model Plant 2 for well pads, Model Plant 2 for 

gathering and boosting stations, and Model Plant 1 for processing plants and transmission and storage 

facilities.
8-25

Table 8-13. Summary of the Model Plant Cost 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 from reducing the amount 

of natural gas as the result of equipment leaks.
8-26

The component costs were calculated using a LDAR cost spreadsheet developedfor 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 openended 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 lines.

 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 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 for purchasing a TVA or OVA monitoring system was estimated to be $6,500.

The component control effectiveness 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 subpart 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 assumption 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 estimate 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 8-14. Summary of Component Cost Effectiveness for Well Pads 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 235 12 1.84 0.0696 6.64 $11,175 $27,786 $15,063 $399,331 $4,183

Connectors 863 1/0.25a0.308 0.0116 1.11 $7,830 $22,915 $74,283 $1,969,328 $20,628

PRD 10 0 0.164 0.00619 0.591 $48,800 $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

Modified Subpart VVa– Less Frequent Monitoring

Valves 235 1 1.31 0.0496 4.73 $11,175 $23,436 $17,828 $472,640 $4,951

Connectors 863 1/0.125b0.261 0.00983 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. 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.
8-28

Table 8-15. Summary of Component Cost Effectiveness for Gathering and Boosting Stations 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 906 12 7.11 0.268 25.6 $24,524 $43,234 $6,079 $161,162 $1,688

Connectors 2,864 1/0.25a1.02 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 $138,417 $1,450

Connectors 2,864 1/0.125b0.865 0.0326 3.11 $10,914 $23,584 $27,274 $723,067 $7,574

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 8-16. Summary of Incremental Component Cost 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 1/0.25a1.57 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 8-17. Summary of Component Cost 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 1/0.25a0.665 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 1/0.125b0.562 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. This 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 arediscussed 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 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. 

8.4.3.3 Cost Impacts

Costs were calculated using a LDAR cost spreadsheet developedfor 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 openended lines.

 Monthly optical gas imaging monitoring costs are estimated to be $0.50 for valves, connectors, 

pressure relief valve devices, 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 openended 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 same 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 processing 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 that one facility could be monitored 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 single 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 plants 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 component 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 of 
8-33

Table 8-18. Summary of the Model Plant Cost Effectiveness for the Optical Gas Imaging and Method 21 Monitoring 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 $15,428 $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 $114,807 $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 $85,503 $10,096 $267,659 $2,804

3 12.9 0.486 46.4 $329,725 $121,820 $111,060 $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 natural 

 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 modified 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, the 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 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 

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, the 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 developedfor 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 openended lines.

 Monthly optical gas imaging monitoring costs are estimated to be $0.50 for valves, connectors, 

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) 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 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 facility.

 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 8-19. 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 for 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. Therefore, 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 §60.18 of 

40 CFR Part 60;
8-36

Table 8-19. Summary of the Model Plant Cost 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: This 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 well 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 $6,934 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 implementation 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 $245,024 per ton of VOC for Model 

Plant 1. This 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.

8.5.1.2 Gathering and Boosting Stations

The first regulatory option was evaluated for gathering and boosting stations which include the 

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 model plants ranged from $10,327 per ton of VOC for 
8-38

Model Plant 1 to $8,174per 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 stations was Regulatory 

Option 2. The VOC cost effectiveness of this option ranged from $6,079 for valves to $77,310 per ton of 

VOC for open-ended lines. These costs were determined to be unreasonable and therefore this 

regulatory option was also 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 was calculated to be $10,724 per ton of VOC for Model Plant 1 and $8,685 per ton of VOC 

for Model Plant 3. This 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 per ton of VOC. 

This cost effectiveness was determined to be reasonable and therefore this regulatory option was 

accepted.

The second option was evaluated for processing plants and the VOC cost effectiveness ranged from $0 

for open-ended lined and pressure relief 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.

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.

8.5.1.4 Transmission and Storage Facilities
8-39

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 $19,769per ton of 

VOC. The high VOC cost effectiveness is due to the inherent low VOC concentration 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. This cost was determined to be unreasonable 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; therefore 

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 LDAR 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. Nationwide Emission and Cost Analysis of Regulatory Options

Category

Estimated 

Number of 

Sources 

subject to 

NSPS

Facility 

Capital 

Cost ($)

Nationwide 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 $3,352 $2,517 $931 $699 0.218 1.31 0.984
8-41

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. 

Environmental 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 

Sinks1990-2008. 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 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.

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. 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. 
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. 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 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 Field Production and Processing Operation. Prepared for the 

U.S. Environmental Protection Agency. September 1999. 
APPENDIX A

E&P TANKS ANALYSIS FOR STORAGE VESSELS
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 0.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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 100.0000
Tank 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

100.0000
Tank 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 18.878
API 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 138.3153
United 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