Oil and Natural Gas Sector Leaks

Report for Oil and Natural Gas Sector Leaks

Review Panel 

April 2014

Prepared by

U.S. EPA Office of Air Quality Planning and Standards 

(OAQPS)

This information is distributed solely for the purpose of pre-dissemination peer review under applicable 

information quality guidelines. It has not been formally disseminated by EPA. It does not represent and

should not be construed to represent any Agency determination or policy.
ii
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Table of Contents

PREFACE....................................................................................................................................... 1

1.0 INTRODUCTION............................................................................................................ 2

2.0 OIL AND NATURAL GAS SECTOR LEAKS EMISSIONS DATA AND 

EMISSIONS ESTIMATES ............................................................................................................ 4

2.1 Protocol for Equipment Leak Emission Estimates (U.S. EPA, 1995) ............................. 6

2.2 GRI/EPA Methane Emissions from the Natural Gas Industry, Volume 8: Equipment 

Leaks (GRI/U.S. EPA, 1996)........................................................................................... 9

2.3 Greenhouse Gas Reporting Program (U.S. EPA, 2013) ................................................ 16

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

........................................................................................................................................ 17

2.5 Measurements of Methane Emissions at Natural Gas Production Sites in the United 

States (Allen et al., 2013)............................................................................................... 22

2.6 City of Fort Worth Natural Gas Air Quality Study (ERG, 2011) .................................. 24

2.7 Measurements of Well Pad Emissions in Greeley, CO (Modrak, 2012) ....................... 26

2.8 Quantifying Cost-Effectiveness of Systematic Leak Detection and Repair Programs 

Using Infrared Cameras (CL, 2013)............................................................................... 28

2.9 Mobile Measurement Studies in Colorado, Texas, and Wyoming (Thoma, 2012) ....... 29

2.10 Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore 

Oil and Natural Gas Industries (ICF International, 2014).............................................. 31

2.11 Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas 

Processing Plants (Clearstone, 2002)............................................................................. 32

2.12 Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas 

Processing Plants and Upstream Gathering Compressor Stations and Well Sites 

(Clearstone, 2006).......................................................................................................... 34
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3.0 AVAILABLE EMISSIONS MITIGATION TECHNIQUES........................................ 36

3.1 Leak Detection ............................................................................................................... 36

3.1.1 Portable Analyzers ................................................................................. 36

3.1.2 Optical Gas Imaging (IR Camera) ......................................................... 39

3.1.3 Acoustic Leak Detector.......................................................................... 42

3.1.4 Ambient/Mobile Monitoring.................................................................. 44

3.2 Repair ............................................................................................................................. 45

3.2.1 Quantifying Cost-Effectiveness of Systematic Leak Detection and 

Repair Programs Using Infrared Cameras (CL, 2013)........................... 46

3.2.2 Identification and Evaluation of Opportunities to Reduce Methane 

Losses at Four Gas Processing Plants (Clearstone, 2002) ..................... 47

3.2.3 Cost-Effective Directed Inspection and Maintenance Control 

Opportunities at Five Gas Processing Plants and Upstream Gathering 

Compressor Stations and Well Sites (Clearstone, 2006)........................ 48

3.2.4 Natural Gas STAR Directed Inspection and Maintenance (U.S. EPA, 

2003a, U.S. EPA, 2003b, and U.S. EPA, 2003c)................................... 49

3.2.5 Update of Fugitive Equipment Leak Emission Factors (CAPP, 2014).. 52

4.0 SUMMARY ................................................................................................................... 54

5.0 CHARGE QUESTIONS FOR REVIEWERS ............................................................... 55

6.0 REFERENCES............................................................................................................... 57
1

PREFACE

On March 28, 2014 the Obama Administration released a key element called for in the 

President’s Climate Action Plan: a Strategy to Reduce Methane Emissions. The strategy 

summarizes the sources of methane emissions, commits to new steps to cut emissions of this 

potent greenhouse gas, and outlines the Administration’s efforts to improve the measurement of 

these emissions. The strategy builds on progress to date and takes steps to further cut methane 

emissions from several sectors, including the oil and natural gas sector. 

This technical white paper is one of those steps. The paper, along with four others, 

focuses on potentially significant sources of methane and volatile organic compounds (VOCs) in 

the oil and gas sector, covering emissions and mitigation techniques for both pollutants. The 

Agency is seeking input from independent experts, along with data and technical information 

from the public. The EPA will use these technical documents to solidify our understanding of 

these potentially significant sources, which will allow us to fully evaluate the range of options 

for cost-effectively cutting VOC and methane waste and emissions.

The white papers are available at: 

www.epa.gov/airquality/oilandgas/whitepapers.html
2

1.0 INTRODUCTION

The oil and natural gas exploration and production industry in the U.S. is highly dynamic 

and growing rapidly. Consequently, the number of wells in service and the potential for greater 

air emissions from oil and natural gas sources is also growing. There were an estimated 504,000

producing gas wells in the U.S. in 2011 (U.S. EIA, 2012a), and an estimated 536,000 producing 

oil wells in the U.S. in 2011 (U.S. EIA, 2012b). It is anticipated that the number of gas and oil 

wells will continue to increase substantially in the future because of the continued and expanding 

use of horizontal drilling combined with hydraulic fracturing (referred to here as simply 

hydraulic fracturing).

Due to the growth of this sector and the potential for increased air emissions, it is 

important that the U.S. Environmental Protection Agency (EPA) obtain a clear and accurate

understanding of emerging data on air emissions and available mitigation techniques. This paper 

presents the Agency’s understanding of emissions and available emissions mitigation techniques

from a potentially significant source of emissions in the oil and natural gas sector.

Oil and gas production from unconventional formations such as shale deposits or plays 

has grown rapidly over the last decade. Oil and natural gas production is projected to steadily 

increase over the next two decades. Specifically, natural gas development is expected to increase 

by 44% from 2011 through 2040 (U.S. EIA, 2013b) and crude oil and natural gas liquids are 

projected to increase by approximately 25% through 2019 (U.S. EIA, 2013b). According to the 

U.S. Energy Information Administration (EIA), over half of new oil wells drilled co-produce

natural gas (U.S. EIA, 2013a).The projected growth is primarily led by the increased 

development of shale gas, tight gas, and coalbed methane resources utilizing new production 

technology and techniques such as horizontal drilling and hydraulic fracturing. 

Along with the increase in number of wells, the amount of related equipment that has the 

potential to leak will increase as well. The emissions that occur from leaks are in the form of 

gasses or evaporated liquids that escape to the atmosphere. Some of the potential leak emissions 

from these sources include methane and VOCs. The proportion of the different types of air 
3

emissions is affected by the composition of the gas in the formation. For example, there tends to 

be a higher concentration of VOCs in wet gas plays than in dry gas plays.

The emissions data and the mitigation techniques in this paper are based on the onshore 

natural gas leak emissions that occur from natural gas production, processing, transmission, and 

storage. However, some of these emissions estimates and mitigation techniques are also 

applicable to oil wells that co-produce natural gas. 

For the purposes of this paper, leaks are defined as VOC and methane emissions that 

occur at onshore facilities upstream of the natural gas distribution system (i.e., upstream of the 

city gate). This includes leak emissions from natural gas well pads, oil wells that co-produce

natural gas, gathering and boosting stations, gas processing plants, and transmission and storage 

infrastructure. Potential sources of leak emissions from these sites include agitator seals, 

compressors seals, connectors, pump diaphragms, flanges, hatches, instruments, meters, openended lines, pressure relief devices, pump seals, valves, and improperly controlled liquids 

storage.1For the purposes of this paper, emissions from equipment intended to vent as part of 

normal operations, such as gas driven pneumatic controllers, are not considered leaks. The 

definition of leak emissions in this paper was derived by reviewing the various approaches taken 

in the available literature. Many studies and data sources define leak emissions differently, 

therefore, in the discussion of these various sources in Section 2 the definition each study uses is 

compared to the definition presented here.

Leak emissions occur through many types of connection points (e.g., flanges, seals, 

threaded fittings) or through moving parts of valves, pumps, compressors, and other types of 

process equipment. Changes in pressure, temperature and mechanical stresses on equipment may 

eventually cause them to leak. Leak emissions can also occur when connection points are not 

fitted properly, which causes leaks from points that are not in good contact. Other leaks can 

occur due to normal operation of equipment, which over time can cause seals and gaskets to 

 

1 Emissions from storage vessels are often required to be controlled by state or federal regulations (e.g., reduced by 

95%). Emissions beyond the required level of control from control equipment that is not operating properly, such as 

leaking vapor recovery units or improperly sized combustors, are considered leaks for the purposes of this white 

paper.
4

wear. Weather conditions can also affect the performance of seals and gaskets that are intended 

to prevent leaks. Lastly, leak emissions can occur from equipment that is not operating correctly, 

such as storage vessel thief hatches that are left open or separator dump valves that are stuck 

open.

This document provides a summary of the EPA’s understanding of VOC and methane leak 

emissions at onshore oil and natural gas production, processing, and transmission facilities. This 

includes available emission data, estimates of VOC and methane emissions and available 

mitigation techniques. Section 2 of this document describes the EPA’s understanding of 

emissions from leaks at onshore oil and natural gas production, processing, and transmission 

facilities, and Section 3 discusses available mitigation techniques to reduce emissions from leaks 

at these facilities. Section 4 summarizes the EPA’s understanding based on the information 

presented in Sections 2 and 3, and Section 5 presents a list of charge questions for reviewers to 

assist the EPA with obtaining a more comprehensive picture of VOC and methane emissions 

from leaks and available mitigation techniques.

2.0 OIL AND NATURAL GAS SECTOR LEAKS EMISSIONS DATA 

AND EMISSIONS ESTIMATES

There are a number of published studies that have estimated leak emissions from the 

natural gas production and petroleum, processing and transmission sector. These studies have 

used different methodologies to estimate these emissions, including the use of equipment counts 

and emission factors, extrapolation of emissions from equipment, and measurement and analysis 

of leaks. In some cases the studies focus on different portions of the natural gas production and 

petroleum, processing and transmission and storage sector (e.g., well sites), while others try to 

account for all leak emissions across the oil and gas sectors. Some of these studies are listed in 

Table 2-1, along with an indication of the type of information contained in the study (i.e., activity 

level). 
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Table 2-1. Summary of Major Sources of Leaks Emissions Information

Name Affiliation

Year of 

Report Activity Factor

Protocol for Equipment 

Leak Emission Estimates 

(U.S. EPA, 1995)

U.S. 

Environmental 

Protection 

Agency

1995 None

Methane Emissions from 

the Natural Gas Industry: 

Equipment Leaks

(GRI/U.S. EPA, 1996)

Gas Research 

Institute (GRI)/ 

U.S. 

Environmental 

Protection 

Industry

1996 Nationwide

Greenhouse Gas Reporting 

Program (U.S. EPA, 2013)

U.S.

Environmental 

Protection 

Agency

2013 Facility

Inventory of Greenhouse 

Gas Emissions and Sinks: 

1990-2012 (U.S. EPA, 

2014)

U.S. 

Environmental 

Protection 

Agency

2014 Regional

Measurements of Methane 

Emissions at Natural Gas 

Production Sites in the 

United States (Allen et al., 

2013)

Multiple 

Affiliations, 

Academic and 

Private

2013 Nationwide

City of Fort Worth Natural 

Gas Air Quality Study, 

Final Report (ERG, 2011)

City of Fort 

Worth 2011 Fort Worth, TX

Measurements of Well Pad 

Emissions in Greeley, CO

(Modrak, 2012)

ARCADIS/Sage 

Environmental 

Consulting/U.S. 

Environmental 

Protection 

Agency

2012 Colorado

Quantifying CostEffectiveness of Systematic 

Leak Detection and Repair 

Programs Using Infrared 

Cameras (CL, 2013)

Carbon Limits 2013 Canada and the U.S.

Mobile Measurement 

Studies in Colorado, Texas, 

and Wyoming (Thoma, 

2012)

U.S.

Environmental 

Protection 

Agency

2012 and 2014 Colorado, Texas, and Wyoming

Economic Analysis of 

Methane Emission 

Reduction Opportunities in 

the U.S. Onshore Oil and 

Natural Gas Industries

(ICF International, 2014)

ICF 

International 2014 Nationwide
6

Name Affiliation

Year of 

Report Activity Factor

Identification and 

Evaluation of 

Opportunities to Reduce 

Methane Losses at Four 

Gas Processing Plants 

(Clearstone, 2002)

Clearstone 

Engineering,

Ltd.

2002 4 gas processing plants

Cost-Effective Directed 

Inspection and 

Maintenance Control 

Opportunities at Five Gas 

Processing Plants and 

Upstream Gathering 

Compressor Stations and 

Well Sites (Clearstone, 

2006)

Clearstone 

Engineering, 

Ltd.

2006 5 gas processing plants, 12 well sites, 7 

gathering stations

Although methane emissions from oil and natural gas production operations have been 

measured, analyzed and reported in studies spanning the past few decades, VOC emissions from 

these operations are not as well represented. 

2.1 Protocol for Equipment Leak Emission Estimates (U.S. EPA, 1995)

The EPA protocol provides standard procedures for estimating the total organic 

compound mass emissions from leaks at oil and natural gas production facilities. The protocol 

provides four different approaches for estimating leak mass emissions at oil and natural gas 

production sites. The correlation equations and emission factors were developed from leak data 

collected from refineries, marketing terminals, oil and gas production operations and synthetic 

organic chemical manufacturing industry (SOCMI) facilities.

Emission factors and correlations have been developed for the following equipment

types: valves, pumps, compressors, pressure relief valves, connectors, flanges, and open-ended 

lines. An "others" category has also been developed for the petroleum industry. Development of 

emission factor and correlation equations for the oil and natural gas production facilities were 

derived from data from six gas plants that were screened by the EPA and the American 

Petroleum Institute 2and from leak emission measurement data from 24 oil and natural gas 

 

2 DuBose, D.A., J.I. Steinmetz, and G.E. Harris (Radian Corporation). Frequency of Leak Occurrence and Emission
7

production facilities collected by the American Petroleum Institute.

3,4

The emissions calculated 

from these emission factors and correlation equations are leak emissions that occur at onshore oil 

and natural gas production and natural gas processing facilities.

Protocol Leak Estimation Approaches

The protocol document provides four approaches that can be used to estimate mass 

emissions from leaks. 

Average Emission Factor Approach

The first approach involves counting the components by type (e.g., valves, pump seals, 

connectors, flanges, and open-ended lines) and service (e.g., gas, heavy oil, light oil, and 

water/oil) at the facility and applying the appropriate average oil and gas production operations 

emission factors to these counts (see Table 2-4 in U.S. EPA, 1995) to calculate the total organic 

compound emissions from leaking equipment. There is also an “other” equipment type emission 

factor that was derived for compressors, diaphragms, drains, dump arms, hatches, instruments, 

meters, pressure relief valves, polished rods, relief valves, and vents.

Although the average emission factors are in units of kilogram per hour per individual 

source, it is important to note that these factors are most valid for estimating emissions from a

population of equipment (U.S. EPA, 1995). The average factors are not intended to be used for 

estimating emissions from an individual piece of equipment over a short time period (e.g., 1 

hour).

 

Factors for Natural Gas Liquid Plants. Final Report. Prepared for U.S. Environmental Protection Agency. Research

Triangle Park, NC. EMB Report No. 80-FOL-1. July 1982.

3

Fugitive Hydrocarbon Emissions from Oil and Gas Production Operations, API 4589, Star Environmental, 

Prepared for American Petroleum Institute, 1993.

4 Emission Factors for Oil and Gas Production Operations, API 4615, Star Environmental, Prepared for American 

Petroleum Institute, 1995.
8

Screening Ranges Approach

The second approach to estimating leak emissions is the screening range approach. This 

approach is intended primarily to aid in the analysis of old datasets that were collected for older 

regulations that used 10,000 parts per million by volume (ppmv) as the leak definition. This 

approach uses the results from EPA Method 21 measurement of leak concentration of 

components to determine the number of components with a leak greater than or equal to 10,000 

parts per million (ppm) and the number of components with a leak less than 10,000 ppm. The 

estimated emissions are then calculated using the count of components by type, service, and 

screening value (≥10,000 ppm or <10,000 ppm) at the facility and applying the appropriate 

average oil and gas production operations emission factors to these counts (see Table 2-8 in U.S. 

EPA, 1995).

This screening range approach is a better indication of the actual leak rate from individual 

equipment than the average emission factor approach (U.S. EPA, 1995). However, available data 

indicate that measured mass emission rates can vary considerably from the rates predicted by use 

of these screening range emission factors.

EPA Correlation Approach

The third approach is a correlation approach that uses the measured Method 21 screening 

value (in ppm) for each component and inputs that screening value into correlation equations that 

calculate the emission rate (see Table 2-10 in U.S. EPA, 1995). This approach offers an 

additional refinement to estimating emissions from leaks by providing an equation to predict 

mass emission rate as a function of concentration determined by EPA Method 21 screening for a

particular equipment type. Correlations for the petroleum industry apply to refineries, marketing 

terminals and oil and gas production operations. The petroleum industry correlation equations 

estimate total organic compound (TOC) emission rates.

The EPA Correlation Approach is preferred when actual screening values (in ppm) are 

available. Correlations can be used to estimate emissions for the entire range of non-zero 

screening values, from the highest potential screening value to the screening value that represents 

the minimum detection limit of the monitoring device. This approach involves entering the non-
9

zero, non-pegged screening value into the correlation equation, which predicts the TOC mass 

emission rate based on the screening value. Default zero emission rates are used for screening 

values of zero ppmv and pegged emission rates are used for pegged screening values, where the 

screening value is beyond the upper limit measured by the portable screening device.

The "default-zero" leak rate is the mass emission rate associated with a screening value of 

zero. (Note that any screening value that is less than or equal to ambient background

concentration is considered a screening value of zero.) The correlations mathematically predict 

zero emissions for zero screening values. However, data collected by the EPA show this 

prediction to be incorrect (U.S. EPA, 1995), because mass emissions have been measured from 

equipment having a screening value of zero. A specific goal when revising the petroleum 

industry correlations was to collect mass emissions data from equipment that had a screening 

value of zero. These data were used to determine a default-zero leak rate associated with 

equipment with zero screening values.

Unit Specific Correlation Approach

The fourth approach calls for developing unit-specific correlations and corresponding 

mass emission rates. This is done by measuring the screening value in ppm and measuring the 

mass emission rate by “bagging” the component. A component is bagged by enclosing the 

component to collect leaking vapors. Measured emission rates from bagged equipment coupled 

with screening values can be used to develop unit-specific screening value/mass emission rate 

correlation equations. Unit-specific correlations can provide precise estimates of mass emissions 

from leaks at the process unit. However, it is recommended that unit-specific correlations are 

only developed in cases where the existing EPA correlations do not give reasonable mass 

emission estimates for the process unit (U.S. EPA, 1995). 

2.2 GRI/EPA Methane Emissions from the Natural Gas Industry, Volume 8: 

Equipment Leaks (GRI/U.S. EPA, 1996)

This report provides an estimate of annual methane emissions from leaks from the natural 

gas production sector using the component method. The component method uses average 

emission factors for components and the average number of components per facility to estimate 
10

the average facility emissions. The average facility emissions were then extrapolated to a 

national estimate using the number of natural gas production facilities.

The study used two approaches to estimate component emissions for the onshore natural 

gas production, offshore natural gas production, natural gas processing, natural gas transmission 

and natural gas storage sectors. The first approach involved screening components using a 

portable hydrocarbon analyzer and using EPA correlation equations (U.S. EPA, 1995) to 

estimate the leaking emissions. The EPA correlation equations provide an average leak rate per 

source using the equipment type (e.g., connectors, flanges, open-ended lines, pumps, valves, 

other), type of material (e.g., gas, heavy oil, light oil, water/light oil), the leak definition used, 

and the leak fraction determined by the screening. This approach was used to determine 

component emission factors for some onshore production sources, natural gas processing and the 

offshore production sector.

The screening of components involved using a portable instrument to detect leaks around, 

flanges, valves, and other components by traversing the instrument probe over the entire surface 

of the component. The components were divided into the following categories:

 Valves (gas/vapor, light liquid, heavy liquid)

 Pump Seals (light liquid, heavy liquid)

 Compressor Seals (gas/vapor)

 Pressure Relief Valves (gas/vapor)

 Connectors, which include flanges and threaded unions (all services)

 Open-Ended Lines (all services)

 Sampling Connections (all services)

All components associated with an equipment source or facility were screened using the 

procedures specified in EPA Method 21. The maximum measured concentration was recorded 

using a portable instrument that met the specifications and performance criteria in EPA Method 

21. In general, an organic vapor analyzer (OVA) that used a flame ionization detector (FID) was 
11

used for conducting the screening measurements. A dilution probe was used to extend the upper 

range of the instrument from 10,000 to 100,000 ppmv.

The second approach used the GRI Hi-FlowTM (trademark of the Gas Research Institute) 

sampler or a direct flow measurement to replace data measured using the enclosure method. This 

method was used to determine emission factors for some of the offshore production sources. The 

sampler has a high flow rate and generates a flow field around the component that captures the 

entire leak. As the sample stream passes through the instrument, both the flow rate and the total 

hydrocarbon (THC) concentration are measured. The mass emission rate can then be determined 

using these measurements. Offshore leak emissions are not covered in this paper; therefore, the 

estimates derived from this method will not be discussed further.

For onshore natural gas production, the facilities were broken up into two categories; 

eastern natural gas production and western gas production to account for regional differences in 

the methane content of the natural gas. The sources of these leak emissions include gas wells, 

separators, heaters, dehydrators, metering runs and gathering compressors. 

A summary of the average equipment emissions, activity factor, and annual methane 

emissions for the onshore production sector is presented in Table 2-2. These factors have been 

used in other reports and studies of methane emissions from the oil and gas sector, including the 

Inventory of U.S. Greenhouse Gas Emissions and Sinks, which will be discussed in more detail 

in Section 2.1.4.

As shown in the tables, the study estimated that 15,512 million standard cubic feet per 

year (MMscf/yr) of methane are emitted as leaks from 271,928 onshore natural gas production 

wells in the U.S. for the 1992 base year. This converts to approximately 292,930 metric tons

(MT) of methane emitted to the atmosphere in the base year.
12

Table 2-2. GRI/EPA National Annual Emission Estimate for Onshore Natural Gas 

Production in the United States (1992 Base Year)a

Equipment

Average 

Equipment 

Methane 

Emissions 

(scf/yr)

Activity 

Factor, 

Equipment 

Count

Annual 

Methane 

Emissions 

(MMscf)

Annual 

Methane 

Emissions 

(MT)b

90% 

Confidence 

Interval

Eastern U.S.

Gas Well 2,595 129,157 335 6,326 27%

Separator 328 91,670 30.1 568 36%

Heater 5,188 260 1.35 25.5 218%

Dehydrator 7,938 1,047 8.31 157 41%

Meters/Piping 3,289 76,262 251 4,740 109%

Gathering Compressors 4,417 129 0.570 10.8 44%

Eastern U.S. Total 626 11,827 46%

Western U.S.

Gas Well 13,302 142,771 1,899 35,859 25%

Separator 44,536 74,674 3,326 62,805 69%

Heater 21,066 50,740 1,069 20,186 110%

Dehydrator 33,262 36,777 1,223 23,094 32%

Meters/Piping 19,310 301,180 5,816 109,823 109%

Sm Gathering Compressorsc87,334 16,915 1,477 27,895 93%

Lg Gathering Compressorsd552,000 96 53.0 1,001 136%

Gathering Stationse1,940,487 12 23.3 440 176%

Western U.S. Total 14,886 281,103 45%

Total 15,512 292,930 -

a - Derived from Tables 5-2 and 5-3 (GRI/U.S. EPA, 1996).

b – Annual methane emissions calculated assuming methane density of 41.63 lb/Mscf.

c – Sm. gathering compressor emission factor does not include compressor seal emissions.

d – Lg. gathering compressor emission factor does not include compressor seal or compressor blowdown emissions.

e – Gathering station emission factor does not include site blowdown line emissions.
13

The national annual methane emissions from natural gas processing were calculated 

using published statistics from the Oil and Gas Journal. The 1992 data from the journal listed the 

total number of natural gas processing plants to be 726. The national methane emissions were 

calculated using this activity factor and the average facility methane emissions for a natural gas 

processing plant. The plant methane emissions were calculated using average component counts 

for gas processing equipment (e.g., valves, connectors, open-ended lines, pressure relief valves, 

blowdown open-ended lines, compressor seals and miscellaneous). For natural gas processing 

plants, the average emissions from equipment was estimated to be 2.89 MMscf/yr (18.9 MT). 

The annual methane emissions from the equipment associated with reciprocating compressors 

and the equipment associated with centrifugal compressors located at natural gas processing 

plants were estimated to be 0.538 MMscf/yr (10.2 MT) and 0.031 MMscf/yr (0.585 MT), 

respectively, in 1992. These methane emissions from the gas processing plant and compressors 

do not include emissions from starter lines, blowdown lines or compressor seals, which are 

considered to be vented emissions and not leaks for the purposes of this paper. The ratio of 

reciprocating and centrifugal compressors located at these plants was based on site visit data 

from 11 natural gas processing plants. The ratio determined from this data was calculated to be 

85% reciprocating and 15% centrifugal. Table 2-3 summarizes the national annual methane 

emissions from natural gas processing plants, which was estimated to be 3,968 MMscf or 74,921

MT.
14

Table 2-3. GRI/EPA National Annual Emission Estimate for Natural Gas Processing Plants

in the United States (1992 Base Year)a

Equipment

Average 

Facility

Methane 

Emissions 

(MMscf/yr)

Activity 

Factor, 

Number of 

Plants/

Compressors

Annual 

Methane 

Emissions 

(MMscf)

Annual 

Methane 

Emissions 

(MT)b

90% 

Confidence 

Interval

Gas Processing Plantc2.40 726 1,744 32,925 27%

Reciprocating Compressorsd0.538 4,092 2,201 41,571 36%

Centrifugal Compressorse0.031 726 22.5 425 218%

Total 3,968 74,921 46%

a - Derived from Table 5-5 (GRI/U.S. EPA, 1996).

b – Annual methane emissions calculated assuming methane density of 41.63 lb/Mscf.

c – Gas processing plant emission factor does not include site blowdown emissions.

d – Reciprocating compressor emission factor does not include rod packing, blowdown or starter emissions.

e – Centrifugal compressor emission factor does not include compressor seal, blowdown or starter emissions.

The annual methane emission from transmission compressor stations was calculated 

using activity data based on statistics by the Federal Energy Regulatory Commission (FERC). 

The data reported to FERC account for 70% of the total transmission pipeline mileage. The split 

between reciprocating and turbine compressors was estimated using data from the GRI 

TRANSDAT database. The average methane emissions from compressor station equipment were 

estimated to be 3.01 MMscf/yr (56.8 MT) in 1992. The annual methane emissions from the 

equipment associated with reciprocating compressors and the equipment associated with 

centrifugal compressors located at transmission stations were estimated to 0.552 MMscf/yr (10.4 

MT) and 0.018 MMscf/yr (0.34 MT), respectively. Table 2-4 summarizes the national annual 

methane leak emissions from natural gas transmission stations, which was estimated to be 50,733 

MMscf or 957,999 MT. These methane emissions from the compressor station and compressors 

do not include emissions from starter lines, blowdown lines or compressor seals, which are 

considered to be vented emissions and not equipment leaks for the purposes of this paper.
15

Table 2-4. GRI/EPA National Annual Emission Estimate for Natural Gas Transmission 

Compressor Stations in the United States (1992 Base Year)a

Equipment

Average 

Facility

Methane 

Emissions 

(MMscf/yr)

Activity 

Factor, 

Number of 

Stations/

Compressors

Annual 

Methane 

Emissions 

(MMscf)

Annual 

Methane 

Emissions 

(MT)b

90% 

Confidence 

Interval

Compressor Stationsc1.94 1,700 3,298 62,276 103%

Reciprocating Compressorsd0.552 6,799 3,753 70,869 68%

Centrifugal Compressorse0.018 681 12.3 231 44%

Total 50,733 957,999 52%

a - Derived from Table 5-6 (GRI/U.S. EPA, 1996).

b – Annual methane emissions calculated assuming methane density of 41.63 lb/Mscf.

c – Compressor station emission factor does not include site blowdown emissions.

d – Reciprocating compressor emission factor does not include rod packing, blowdown or starter emissions.

e – Centrifugal compressor emission factor does not include compressor seal, blowdown or starter emissions.

For natural gas storage facilities, the annual methane emissions were calculated using 

activity data based on published data in Gas Facts. The number of compressors and 

injection/withdrawal wells located at natural gas storage facilities were estimated using data 

collected from site visits to eight facilities. The average methane emissions from natural gas 

storage facilities were estimated to be 6.80 MMscf/yr (128 MT). The annual average methane 

emissions from an injection/withdrawal well were estimated to be 0.042 MMscf/yr (0.79 MT). 

The annual methane emissions from equipment for reciprocating and centrifugal compressors 

were estimated to be 0.47 MMscf/yr (8.9 MT) and 0.017 MMscf/yr (0.32 MT), respectively, in 

1992. The national methane emissions from storage facilities were estimated to be 4,644 MMscf 

or 87,713 MT and are provided in Table 2-5. These methane emissions from the storage facility 

and compressors do not include emissions from starter lines, blowdown lines or compressor 

seals, which are considered to be vented emissions and not leaks for the purposes of this paper.
16

Table 2-5. GRI/EPA National Annual Emission Estimate for Natural Gas Storage Facilities

in the United States (1992 Base Year)a

Equipment

Average 

Facility

Emissions 

(MMscf/yr)

Activity 

Factor, 

Number of 

Facilities/

Compressors

Annual 

Methane 

Emissions 

(MMscf)

Annual 

Methane 

Emissions 

(MT)b

90% 

Confidence 

Interval

Storage Facilitiesc6.80 475 3,230 61,004 100

Injection/Withdrawal Wells 0.042 17,999 756 14,275 76

Reciprocating Compressorsd0.47 1,396 656 12,390 80

Centrifugal Compressorse0.017 136 2.3 43.7 130

Total 4,644 87,713 57

a - Derived from Table 5-7 (GRI/U.S. EPA, 1996).

b – Annual methane emissions calculated assuming methane density of 41.63 lb/Mscf.

c – Storage facility emission factor does not include site blowdown emissions.

d – Reciprocating compressor emission factor does not include rod packing, blowdown or starter emissions.

e – Centrifugal compressor emission factor does not include compressor seal, blowdown or starter emissions.

2.3 Greenhouse Gas Reporting Program (U.S. EPA, 2013)

In October 2013, the EPA released the 2012 greenhouse gas (GHG) data for Petroleum 

and Natural Gas Systems5collected under the Greenhouse Gas Reporting Program (GHGRP). 

The GHGRP, which was required by Congress in the FY2008 Consolidated Appropriations Act, 

requires facilities to report data from large emission sources across a range of industry sectors, as 

well as suppliers of certain GHGs and products that would emit GHGs if released or combusted.

The GHGRP covers a subset of national emissions, as facilities are required to submit 

annual reports only if total GHG emissions are 25,000 metric tons carbon dioxide equivalent 

(CO2e) or more. Facilities use uniform methods prescribed by the EPA to calculate GHG 

emissions, such as direct measurement, engineering calculations, or emission factors. In some 

cases, facilities have a choice of using one of the multiple available calculation methods for an 

emission source provided.

 

5 The implementing regulations of the Petroleum and Natural Gas Systems source category of the GHGRP are 

located at 40 CFR Part 98, subpart W.
17

Methods for calculating emissions from leaks depend on the industry segment. Facilities 

in the onshore petroleum and natural gas production segment use population counts and 

population emission factors for calculating emissions from leaks. Population counts are 

determined based on either (1) a count of all major equipment (wellheads, separators, 

meters/piping, compressors, in-line heaters, dehydrators, heater-treaters, and headers) multiplied 

by average component counts specified in the subpart W regulations, or (2) a count of each 

component individually for the facility. Emissions are then calculated by multiplying population 

count by the appropriate population emission factor specified in the subpart W regulations.

Facilities in the onshore gas processing and gas transmission segments use counts of 

leaking components and leak emission factors for calculating emissions from leaks. The counts 

of leaking components are identified during an annual leak survey using an optical gas imaging 

(OGI) instrument, EPA Method 21, infrared (IR) laser beam illuminated instrument, or an 

acoustic leak detection device. Once the leaking components have been identified and counted, 

the emissions are calculated by multiplying the count of a specific type of leaking component by 

the appropriate leak emission factor specified in the subpart W regulations.

For the 2012 reporting year, reported methane emissions from leaks from onshore 

petroleum and natural gas production were 364,453 MT, onshore natural gas processing were 

13,527 MT, and onshore natural gas transmission compression were 15,868 MT.

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

The EPA leads the development of the annual Inventory of U.S. Greenhouse Gas 

Emissions and Sinks (GHG Inventory). This report tracks total U.S. GHG emissions and 

removals by source and by economic sector over a time series, beginning with 1990. The U.S. 

submits the GHG Inventory to the United Nations Framework Convention on Climate Change 

(UNFCCC) as an annual reporting requirement. The GHG Inventory includes estimates of 

methane and carbon dioxide for natural gas systems (production through distribution) and 

petroleum systems (production through refining).

The natural gas production system covers all equipment that process or transport natural 

gas from oil and gas production sites. (All equipment that process or transport hydrocarbon 
18

liquids are covered in the oil systems section of the GHG Inventory.) The natural gas production

segment is broken into six regions (North East, Midcontinent, Rocky Mountain, South West, 

West Coast, and Gulf Coast) and includes estimates for gas wells, separation equipment, 

gathering compressors, gathering pipelines, drilling and well completions, normal operations, 

condensate tank vents, well workovers, liquids unloading, vessel blowdowns, and process upsets.

For the natural gas production segment, only methane emissions from gas wells, field 

separation equipment, and gathering compressor systems will be discussed from the GHG 

Inventory. Leaks from gas wells include emissions from various components, such as connectors 

and valves, on a wellhead. Field separation equipment includes heaters, separators, dehydrators, 

meters and piping. Gathering compressor systems include reciprocating compressors, equipment 

such as scrubbers and coolers associated with the compressors, and the piping. Leaks from field 

separation equipment and gathering compressor systems include emissions from components in 

these equipment and systems. The only exception is the gathering compressors source that 

includes both leak emissions and vented emissions from compressor seals in the GHG Inventory.

(Note: Vented emissions from compressors are not defined as leaks in this paper, but are

discussed in the white paper on compressors.) The 2014 GHG Inventory (published in 2014; 

containing emissions data for 1990-2012) calculates potential6 methane leak emissions from gas 

wells and field separation equipment using emission factors from the GRI/EPA study (GRI/U.S. 

EPA, 1996). The emission factors from the GRI/EPA study are split regionally into Eastern and 

Western factors. These emission factors are adapted in the 2014 GHG Inventory for each of the 

NEMS regions by adjusting the GRI/EPA emission factors for the NEMS region-specific 

methane content in produced natural gas. All of the emission factors from the GRI/EPA study 

assume methane content of 78.8% in the produced natural gas. However, the 2014 GHG 

 

6 The calculation of emissions for each source of in the GHG Inventory generally involves first the calculation of 

potential emissions (methane that would be emitted in the absence of controls), then the compilation of emissions 

reductions data, and finally the calculation of net emissions by deducting the reductions data from the calculated 

potential emissions. This approach was developed to ensure an accurate time series that reflects real emission trends. 

Key data on emissions from many sources are from GRI/U.S. EPA 1996, and since the time of this study practices 

and technologies have changed. While the study still represents best available data for some emission sources, using 

these emission factors alone to represent actual emissions without adjusting for emissions controls would in many 

cases overestimate emissions. As updated emission factors reflecting changing practices are not available for most 

sources, the GRI/U.S. EPA 1996 emission factors continue to be used for many sources for all years of the GHG 

Inventory, but they are considered to be potential emissions factors, representing what emissions would be if 

practices and technologies had not changed over time.
19

Inventory uses regional methane contents obtained from a 2001 study by the Gas Technology 

Institute (GTI) on unconventional gas and gas composition7to adjust the GRI/EPA emission 

factors to account for the regional methane content differences. The GHG Inventory emissions 

are then calculated by applying the modified GRI/EPA emission factors to component counts for 

each year of the GHG Inventory. Because component counts are not available for each year of 

the GHG Inventory, a set of industry activity data drivers was developed and used to update 

activity data.

8

The 2014 GHG Inventory, emission factors, and methane emissions are presented 

by region in Table 2-6. The 2014 GHG Inventory estimated 332,662 MT of potential methane 

leak emissions from gas wells and field separation equipment from natural gas production 

activities in 2012.

Table 2-6. 2011 Data and Calculated Methane Potential Leak Emissions for the Natural 

Gas Production Segment by Regiona

Region Activity Activity Data Emission Factor

Calculated 

Potential 

Emissions (MT)

North East

Associated Gas 

Wells 38,770 NA NA

Non-associated Gas 

Wells 112,607 7.67 scfd/well 6,071

Gas Wells with 

Hydraulic 

Fracturing

46,367 7.54 scfd/well 2,457

Heaters 318 15.38 scfd/heater 34

Separators 112,872 0.97 scfd/separator 771

Dehydrators 22,164 23.53 scfd 

dehydrator 3,665

Meters/Piping 7,910 9.75 scfd/meter 542

 

7 GRI-01/0136 GTI's Gas Resource Database: Unconventional Natural Gas and Gas Composition Databases. Second 

Edition. August, 2001.

8

For example, recent data on various types of field separation equipment in the production stage (i.e., heaters, 

separators, and dehydrators) are unavailable. Each of these types of field separation equipment was determined to 

relate to the number of gas wells. Using the number of each type of field separation equipment estimated by 

GRI/EPA in 1992, and the number of gas wells in 1992, a factor was developed that is used to estimate the number 

of each type of field separation equipment throughout the time series. The annual well count data used for these 

sources were obtained from a production database maintained by DrillingInfo, Inc. (DrillingInfo, 2012).
20

Region Activity Activity Data Emission Factor

Calculated 

Potential 

Emissions (MT)

Midcontinent

Associated Gas 

Wells 27,470 NA NA

Non-associated Gas 

Wells 77,896 7.45 scfd/well 4,080

Gas Wells with 

Hydraulic 

Fracturing

30,156 8.35 scfd/well 1,771

Heaters 43,869 14.9 scfd/heater 4,596

Separators 47,003 0.94 scfd/separator 311

Dehydrators 15,064 95.54 scfd 

dehydrator 10,118

Meters/Piping 143,186 9.45 scfd/meter 9,509

Rocky Mountain

Associated Gas 

Wells 32,598 NA NA

Non-associated Gas 

Wells 9,665 35.05 scfd/well 2,381

Gas Wells with 

Hydraulic 

Fracturing

73,755 40.72 scfd/well 21,115

Heaters 38,040 56.73 scfd/heater 15,172

Separators 41,627 120 scfd/separator 35,099

Dehydrators 11,630 89.58 scfd 

dehydrator 7,324

Meters/Piping 97,399 52.01 scfd/meter 35,609

South West

Associated Gas 

Wells 155,119 NA NA

Non-associated Gas 

Wells 13,860 37.24 scfd/well 3,628

Gas Wells with 

Hydraulic 

Fracturing

27,627 37.24 scfd/well 7,232

Heaters 11,243 58.97 scfd/heater 4,661

Separators 23,316 125 scfd/separator 20,435

Dehydrators 5,784 93.11 scfd 

dehydrator 3,786

Meters/Piping 55,885 54.06 scfd/meter 21,237
21

Region Activity Activity Data Emission Factor

Calculated 

Potential 

Emissions (MT)

West Coast

Associated Gas 

Wells 29,726 NA NA

Non-associated Gas 

Wells 1,999 42.49 scfd/well 597

Gas Wells with 

Hydraulic 

Fracturing

95 42.49 scfd/well 28

Heaters 2,094 67.29 scfd/heater 991

Separators 1,529 142 scfd/separator 1,529

Dehydrators 292 106 scfd dehydrator 218

Meters/Piping 3,994 61.68 scfd/meter 1,732

Gulf Coast

Associated Gas 

Wells 39,709 NA NA

Non-associated Gas 

Wells 27,024 7.96 scfd/well 1,512

Gas Wells with 

Hydraulic 

Fracturing

49,862 7.96 scfd/well 2,789

Heaters 17,222 64.60 scfd/heater 7,821

Separators 50,591 136.57

scfd/separator 48,571

Dehydrators 10,719 102.00 scfd 

dehydrator 7,686

Meters/Piping 90,288 59.21 scfd/meter 37,584

a Derived from ANNEX 3 Methodological Descriptions for Additional Source or Sink Categories (U.S. EPA, 2014).

The gas processing and gas transmission segments are not broken into regions like the 

gas production segment in the 2014 GHG Inventory. Instead, these segments provide national 

level emission estimates for their individual emission sources. For both segments, leak emissions

include emissions from all components in the gas plants and on compression systems. The 

transmission segment leaks include leaks from transmission pipelines. The 2014 GHG Inventory 

calculates potential methane emissions from these sources using emission factors from the 

GRI/EPA study (GRI/U.S. EPA, 1996) and a 2010 ICF International (ICF) memo to the EPA on 

centrifugal compressors (ICF, 2010). The GHG Inventory emissions are calculated by applying 
22

the emission factors to activity counts (in this case, gas plants, compressor station counts, 

compressor counts, and pipeline miles) for each year of the inventory. Because some component 

counts are not available for each year of the GHG Inventory, a set of industry activity data 

drivers was developed and used to update activity data.

9

The 2014 GHG Inventory gas 

processing and gas transmission sources, emission factors, and methane emissions are presented 

in Table 2-7. For 2012, the 2014 GHG Inventory estimated 33,681 MT of potential methane

emissions from gas processing leak emissions and 114,348 MT of potential methane emissions 

from gas transmission leak emissions.

Table 2-7. 2011 Data and Calculated Methane Potential Leak Emissions for the Natural 

Gas Processing and Natural Gas Transmissions Segmentsa

Segment Activity

Activity 

Data Emission Factor

Calculated 

Potential 

Emissions 

(MT)

Gas Processing Plants 606 7,906 scfd/plant 33,681

Gas 

Transmission

Pipeline Leaks 303,126 1.55 scfd/mile 3,311

Station 1,799 8,778 scfd/station 111,037

a Derived from ANNEX 3 Methodological Descriptions for Additional Source or Sink Categories, pg. A-177 (U.S. 

EPA, 2014).

For 2012, the 2014 GHG Inventory data estimates that potential emissions from leaks in 

production, processing and transmission are approximately 480,691 million MT of methane or 

about 8% of overall potential methane emissions from oil and gas.

2.5 Measurements of Methane Emissions at Natural Gas Production Sites in the United 

States (Allen et al., 2013)

A study completed by multiple academic institutions and consulting firms was conducted 

to gather methane emissions data at onshore natural gas sites in the U.S. This study used direct 

 

9

For example, individual compressor counts and compressor station counts are not available. Instead, these are 

obtained using a ratio of compressors to gas plants (for processing) and ratios of stations to pipeline miles and 

compressors to pipeline miles (for transmission) in the base year 1992. The 1992 ratios are then multiplied by the 

activity drivers, i.e., gas plant count or miles of pipeline, in the current year to estimate activity in current year.
23

measurements of methane emissions at 190 onshore natural gas sites in the U.S. (150 production 

sites, 27 well completion flowbacks, 9 well unloadings, and 4 workovers). The study covered the 

natural gas production segment.

For leak emissions, the study collected emissions data from 150 sites, 146 sites with wells 

and 4 sites with separators and other equipment on site. Leak emissions data from piping, valves, 

separators, wellheads, and connectors are provided in Table 2-8. The first step used to identify 

leaks from natural gas production sites was to scan the site using an OGI camera. The threshold 

for detection of a leak with the camera was 30 g/hr (Allen et al., 2013). After leaks were 

identified by the camera, the flow rate and the concentration of the leaks were measured using a 

Hi-Flow SamplerTM and the mass emission rate calculated. The instrument was calibrated using 

samples consisting of pure methane in ambient air. To account for the effect of ethane, propane, 

butane and higher alkanes on the leak measurements, gas composition data were collected for 

each natural gas production site that was visited. Based on the gas composition, the percentage of

carbon accounted for by methane in the sample stream was determined. This percentage,

multiplied by the total gas flow rate reported by the instrument, was the methane flow.

Table 2-8. Summary of Emissions from Leaks

Emissions Per Wella

Appalachian Gulf Coast Midcontinent

Rocky 

Mountain All Facilities

Number of Sites 

with Wells 

Visited (number 

of wells with 

leaks detected)

47 (30) 54 (31) 26 (19) 19 (17) 146 (97)

Methane 

Emission Rate

(scf/min/well)

0.098 ± 0.059 0.052 ± 0.030 0.046 ± 0.024 0.035 ± 0.026 0.064 ± 0.023

Whole Gas 

Emissions Rate 

(based on site 

specific gas 

composition)

(scf/min/well)

0.100 ± 0.060 0.058 ± 0.033 0.055 ± 0.034 0.047 ± 0.034 0.070 ± 0.024

a All leaks detected with the OGI camera, and does not include emissions from pneumatic pumps and controllers.
24

The study authors concluded the average values of leak emissions per well reported in 

Table 2-8 are comparable to the average values of potential emissions per well for gas wells, 

separators, heaters, piping and dehydrator leaks (0.072 scf methane/min/well) from the 2013 

GHG Inventory, calculated by dividing the potential emissions in these categories in the 2013 

GHG Inventory by the number of wells (Allen et al., 2013).

2.6 City of Fort Worth Natural Gas Air Quality Study (ERG, 2011)

The city of Fort Worth solicited a study that reviewed air quality issues associated with 

natural gas exploration and production. The goals of the study were to answer the following four 

questions:

 How much air pollution is being released by natural gas exploration in Fort Worth?

 Do sites comply with environmental regulations?

 How do releases from these sites affect off-site air pollution levels?

 Are the city’s required setbacks for these sites adequate to protect public health?

To answer these questions, the study collected ambient air monitoring and direct leak and 

vented emissions measurements and performed air dispersion modeling. The study collected data 

from 375 well pads, 8 compressor stations, a gas processing plant, a saltwater treatment facility, 

a drilling operation, a hydraulic fracturing operation, and a completion operation. The point 

source test data was collected using an OGI camera, a toxic vapor analyzer (TVA), a Hi-Flow 

SamplerTM and stainless steel canisters. Each site was surveyed with an OGI camera and, if a 

leak was observed by the camera, the concentration of the leak was measured using the TVA. In 

addition, 10% of the total valves and connectors and the other components were surveyed using 

the TVA to determine leaks at or above 500 ppmv. The emission rates of the leaks identified by 

the OGI camera and the TVA survey were determined using a Hi-Flow SamplerTM to measure 

the volumetric flow rate of the leak. Gas samples from selected leaks were collected in stainless 

steel canisters for VOC and HAP analysis by a gas chromatograph/mass spectrometer (GC/MS). 

Based on the results of the point source leak survey, the study estimated the total organic 

emissions to be 20,818 tons per year or 18,819 megagrams per year (Mg/yr), with well pads 
25

accounting for more than 75% of the total emissions. Hydrocarbons with low toxicities 

(methane, ethane, propane, and butane) accounted for approximately 98% of the emissions from 

this study. A summary of the average and maximum emissions from each of the site types is 

provided in Table 2-9. Table 2-10 provides a summary of the measured emissions by equipment 

type (e.g., connector, valve, other). Valves include manual valves, automatic actuation valves, 

and pressure relief valves. Connectors include flanges, threaded unions, tees, plugs, caps and 

open-ended lines where the plug or cap was missing. The category “Other” consists of all 

remaining components such as tank thief hatches, pneumatic valve controllers, instrumentation, 

regulators, gauges, and vents.

Table 2-9. Average and Maximum Point Source Emission Rates by Site Typea

Site Type

TOC (tons/yr) VOC (Tons/yr)

Average Maximum Average Maximum

Well Pad 16 445 0.07 8.6

Well Pad with Compressor(s) 68 4,433 2 22

Compressor Station 99 276 17 43

Processing Facility 1,293 1,293 80 80

a - Derived from Table 3.5-1 (ERG, 2011).
26

Table 2-10. Average and Maximum Point Source Emission Rates by Equipment Typea

Equipment Type

Methane (lb/yr) VOC (lb/yr)

Average Maximum Average Maximum

Connectors 8,918 169,626 27.6 171

Other 20,914 497,430 142 4,161

Valves 27,585 570,083 29.7 123

a - Derived from Emissions Calculation Workbook spreadsheet.

Some general observations of the well pad data provided in the Fort Worth report are:

 At least one leak was detected at 283 out of the 375 well pads monitored with an OGI 

technology with an average of 3.2 leaks detected per well pad;

 The TVA detected at least one leak greater than 500 ppm at 270 of the 375 well pads that 

were monitored with an average of 2.0 leaks detected per well pad;

 The number of wells located on well pads ranged from 0 to 13 with the average number 

of wells being 2.98 with a 99% confidence level of 0.31;

 The average number of components at each well site was 212 valves, 1596 connectors, 3 

storage tanks, and 0.4 compressors;

 124 out of the 375 well pads had at least one compressor onsite;

 There were 17 different owners of the 375 well sites in the Fort Worth area with the 

average number of well sites per owner being 22;

 Of the 1,330 leaks that were detected using either OGI technology or the TVA, 200 

(15%) were classified as connector type leaks, 90 (7%) were classified as valve type 

leaks, and 1,040 (78%) were classified as other type leaks. 

 Of these 1,330 leaks that were detected using OGI technology or the TVA, 1,018 (77%) 

were classified as non-tank leaks and the remaining 312 (23%) were classified as tank 

leaks.

2.7 Measurements of Well Pad Emissions in Greeley, CO (Modrak, 2012)

An onsite direct measurement study of emissions from 23 well pads in areas near 
27

Greeley, CO (Weld County) was performed over a one-week period in July 2011. This study 

used the same source testing contractor and non-invasive leak detection and measurement 

procedures (OGI and Hi-Flow SamplerTM) as in the City of Fort Worth Natural Gas Air Quality 

Study (ERG, 2011). Other than the number of production pads investigated (375 vs. 23), there 

were three major differences in the studies.

 The City of Forth Worth Air Quality Study was conducted in a predominately dry gas 

area of the Barnett shale whereas the Greeley study was conducted in an area with much 

higher relative condensate/oil production rates (wet gas). A typical leak or vented 

emission in a dry gas area is likely to have a higher methane to VOC ratio compared to an 

emission in a wet gas area.

 The State of Colorado requires emissions from condensate/oil tanks to be collected and 

controlled (e.g. routed to an enclosed combustors). In the City of Forth Worth Air Quality 

Study, most storage tanks contained produced water and were not controlled. 

 The City of Fort Worth Air Quality Study used the EPA Compendium Method TO-15 

and ASTM 1945 (for methane) for source canister analysis, whereas the Greeley study 

used the Ozone Precursor method (EPA/600-R-98/161) coupled with ASTM 1946/D1945

analysis of methane, ethane and propane. The canister analysis set used in the Greeley 

study had significantly more overlap for oil and gas product-related compounds (i.e. 

ethane, propane, other alkanes), whereas the TO-15 method provided more coverage for 

HAP compounds.

The objectives of the limited scope Greeley well pad study were to improve 

understanding of methane and speciated VOC emissions and investigate the use of commercially 

available non-invasive measurement approaches for application to wet gas production operations

(including tank emissions).

The average production pad in the Greeley study consisted of 5 wells, 258 valves, 2,583 

connectors, 3 condensate tanks, 1 produced water tank, 4 thief hatches, 5 pressure relief devices, 

3 separators and 1 enclosed combustor control device. A total of 93 emission points were found 

with OGI technology at the 23 production sites and the emission rates were measured using a 

high volume sampler with a subset of 33 additionally sampled using evacuated canisters. A
28

disproportionate number of detected emissions were found to be associated with storage tanks 

(72%). For the purposes of this white paper, a tank-related air emission is considered a leak if it 

exceeds the state or local emission limits. The study authors concluded condensate tank-related 

emissions observed in the Greeley study were not effectively collected and controlled. However,

due to single point and instantaneous nature of the measurements, it is not known if these

uncollected emissions exceed the state allowance.

Considering only emissions measurements with canister analysis, the average methane 

emissions from all storage tanks, excluding samples of known flash emissions, were much lower 

in the Greeley study compared to the City of Fort Worth Air Quality Study, 0.77 tons/year 

(n=21) and 21.9 tons/year (n=54), respectively. In contrast, the average VOC tank related 

emissions were much higher in the Greeley study compared to the City of Fort Worth Air 

Quality Study, 5.38 tons/year and 0.48 tons/year, respectively. Non-tank emissions followed 

similar trends: emissions of methane were higher in the City of Fort Worth Air Quality Study

(7.73 tons/year (n=92) and 1.01 tons/year in the Greeley study (n=5)), while VOC emissions 

were higher in the Greeley study (0.46 tons/year in the Greeley study and 0.02 tons/year in the 

City of Fort Worth Air Quality Study). The authors noted that these emission estimates are based 

on instantaneous measurements. Because tank-related emissions vary diurnally and by season 

and may contain a residual flash emissions component, the extrapolation to yearly values (i.e.,

tons/year) is for informational purposes only and should not be used for comparison to permit or 

control limits. A journal article with additional analysis of these studies is in preparation 

(Modrak, 2012; Brantley et al., 2014a).

2.8 Quantifying Cost-Effectiveness of Systematic Leak Detection and Repair Programs 

Using Infrared Cameras (CL, 2013)

The study presented a summary of 4,293 surveys from two private sector firms that 

provide gas emission detection and measurement services to oil and gas facilities in the U.S. and 

Canada. These surveys only covered certain regions of the U.S. and Canada. The surveys

included three categories of facilities: gas processing plants (614 surveys), compressor stations 

(1,915 surveys; includes both gas transmission and gas gathering systems), and well sites (1,764 

surveys; includes single well heads and sites with up to 15 well heads). The surveys were 
29

conducted using OGI technology to locate leaking components and the leak rates were measured 

using a high-volume sampler. In some cases, where the facility owners did not need a precise 

volume measurement or where the leaking component was difficult to access for measurement,

an estimate (evaluated visually using OGI technology based on the extensive experience of the 

operators) was used to make the decision to repair.

The study found that of the 58,421 components that were identified in the surveys, 

39,505 (68%) were either leaking or venting gas. A summary of the leak rates for each of the 

categories is provided in Table 2-11. As the table shows, the study found that gas processing 

plants had the highest leak rate, followed by compressor stations and then well sites. The study 

noted that vents are the most common source of gas emissions from the identified emission 

sources, and about 40% of the vent emissions come from instrument controllers and compressor 

rod packing. Other vent sources come from production/storage tanks, lube oil vents, 

compressors, pumps, and engines. (Note: vented emissions are not considered leaks for the 

purposes of this paper).

Table 2-11. Distribution of Facilities Within Each Category by Leak Rate

(in Mcf of gas per facility per year)a

Category No leaks ≤ 99 100-499 500-1499 ≥ 1500

Gas processing plants 3% 17% 32% 25% 23%

Compressor stations 11% 30% 36% 15% 9%

Well sites & well batteries 36% 38% 18% 5% 2%

a - Derived from Table 3 (CL, 2013).

The study results show that, for the facilities in the study, gas processing plants are the 

most likely to have leaks and the most likely to have large leaks, followed by compressor 

stations, and, lastly, well sites.

2.9 Mobile Measurement Studies in Colorado, Texas, and Wyoming (Thoma, 2012)

As will be described in detail in Section 3.4, emerging mobile measurement technologies 

are providing new capability for detection and measurement of emissions from upstream oil 
30

and gas production and other sectors. The EPA developed and applied one such mobile 

inspection technique as part of its Geospatial Measurement of Air Pollution (GMAP) program.

(Thoma, 2012; Brantley et al., 2014b). Designed to be a rapidly-deployed inspection approach 

that can cover large areas, OTM 33A can locate unknown emissions (e.g., pipeline leaks or 

malfunctions) and can provide an emission rate assessment for upstream oil and gas sources, 

such as well pads located in relatively open areas. With measurements executed from stand-off 

observation distances of 20 m to 200 m, the mobile approach is not as accurate as onsite direct 

measurements but can provide source strength assessments with an accuracy of +/- 30% under 

favorable conditions with repeat measurements. OTM 33A relies on statistically representative 

downwind plume sampling, relatively obstruction-free line of sight observation, and a 

knowledge of the distance to the source (Thoma, 2012; Brantley et al., 2014b).

The EPA used OTM 33A to conduct several survey field campaigns in Weld County, CO

in July 2010 and July 2011; areas near Fort Worth, TX (Wise, Parker, Tarrant, and Denton 

Counties) in September 2010 and 2011; in Sublette County, WY in June 2011, July 2012 and 

June 2013; and in the Eagle Ford, TX area (Maverick, Dimmit, La Salle, Webb, and Duval 

Counties) in September 2011. A total of 84 methane emission assessments were conducted in 

the Fort Worth area, 216 in WY, 93 in CO, and 22 in the Eagle Ford with offsite canister 

acquisition. Additionally, VOC emission estimates were executed at approximately 46% of 

these measurements. A subset of these field studies are described in (Thoma, 2012) with an 

expanded discussion, and slight revision of results to be published in (Brantley et al., 2014b).

These data are primarily from well pads and represent an integration of all emissions (leak and 

vented) on the site. (Note: Vented emissions are not defined as “leaks” in this paper, therefore, 

the emission rates presented below include emissions that are not considered leaks in this 

paper). The study authors note, as with all instantaneous measurement approaches, the OTM 

33A assessment may capture emissions that are short-term in nature (i.e., flash emissions) so 

extrapolation to annual emissions is difficult. 

The preliminary results from the study (Thoma, 2012) show median methane emission 

rates of 0.21 grams per second (g/s), 0.43 g/s and 0.79 g/s and VOC emission rates of 0.16 g/s, 

0.04 g/s and 0.30 g/s for the CO, TX, and WY studies, respectively (excluding Eagle Ford).
31

The study authors note that using improved analysis procedures, the above median rates will 

likely be revised slightly lower in a future publication. Offsite OGI was used in many cases to 

positively identify the origin of emissions. The study authors concluded that many of the high 

emission values were attributed to maintenance-related issues such as open thief hatches, failed 

pressure relief valves, or stuck dump valves. The difference in VOC emissions between the TX 

studies and the CO and WY studies is a result of the natural gas from the TX well sites being a 

dry natural gas. Additional analysis of the emission measurements including comparisons to 

natural gas, condensate/oil, and produced water production will be contained in a forthcoming 

article (Brantley et al., 2014b).

2.10 Economic Analysis of Methane Emission Reduction Opportunities in the U.S. 

Onshore Oil and Natural Gas Industries (ICF International, 2014)

The Environmental Defense Fund (EDF) commissioned ICF to conduct an economic 

analysis of methane emission reduction opportunities from the oil and natural gas industry to 

identify the most cost-effective approach to reduce methane emissions from the industry. The 

study projects the estimated growth of methane emissions through 2018 and focuses its analysis 

on 22 methane emission sources in the oil and natural gas industry (referred to as the targeted 

emission sources). These targeted emission sources represent 80% of their projected 2018 

methane emissions from onshore oil and gas industry sources. Well site leaks (includes heaters, 

separators, dehydrators and meters/piping) and pipeline leaks are two of the 22 emission sources 

that are included in the study. 

The study relied on the 2013 GHG Inventory for methane emissions data for the oil and 

natural gas sector. The emissions data were revised to include updated information from the 

GHGRP (U.S. EPA, 2013) and the Measurements of Methane Emissions at Natural Gas 

Production Sites in the United States study (Allen et al., 2013). The revised 2011 baseline 

methane emissions estimate was used as the basis for projecting onshore methane emissions to 

2018. One of the major differences in the revised 2011 baseline methane emissions estimate 

developed by ICF is the inclusion of a separate category for gathering and boosting operations. 

The 2013 GHG Inventory includes gathering and boosting operations in the onshore production 

segment and is based on the GRI/EPA measurement study (GRI/U.S. EPA, 1996). 
32

The 2011 baseline methane inventory developed by ICF used the wellhead emission 

factor developed from the University of Texas study (Allen et al., 2013) to estimate leak 

emissions from well sites, which was reported as 97.6 scf/day. This emissions factor was applied 

to the natural gas well counts obtained from World Oil magazine to estimate the total methane 

leak emissions from well sites. These changes resulted in an estimated14 billion cubic feet

(264,000 MT) of methane emissions from wellheads in comparison. 

Leak emissions from heater, separators, dehydrators, and meters/piping in the natural gas 

production sector were calculated using the GRI/EPA emissions factors for each of these 

emission sources. The study estimated methane emissions were 15 billion cubic feet (283,000 

MT) from these sources. 

Natural gas processing plant leak emission were determined by ICF using data from the 

GHGRP (U.S. EPA, 2013) and a list of processing plants maintained by the EIA. The study by 

ICF determined that there are 909 gas processing and treatment facilities in the U.S. The study 

estimated methane emissions from processing facilities to be 3 billion cubic feet (56,600 MT).

The study did not provide specific equipment leak information for the natural gas 

transmission and storage sectors. However, the report did provide information on pipeline leaks 

from transmission of natural gas. The report estimated methane emissions of 0.2 billion cubic 

feet (3,800 MT).

The estimate of total national emissions from leaks in the natural gas production, 

processing, transmission and storage segments for 2011was 604,000 MT of methane.

2.11 Identification and Evaluation of Opportunities to Reduce Methane Losses at Four 

Gas Processing Plants (Clearstone, 2002)

This study, referred to as “Clearstone I,”10 presented the results of the implementation of 

a comprehensive directed inspection and maintenance (DI&M) program at four gas processing 

 

10 “Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas Processing Plants.” 

Prepared for GTI and the U.S. EPA under grant 827754-01-0, by Clearstone Engineering. June 20, 2002. Also, note 

that a follow-up study, referred to as Clearstone II, was released in 2006, which studied five processing plants, one 

being a repeat from the plants studied in Clearstone I. 
33

plants in the western U.S. in 2000. The work done during this study involved a survey of all gas 

service equipment components, as well as the measurement or engineering calculation of gas 

flows into the vent and flare systems. This study did not focus on hydrocarbon liquid services. In 

total, 101,193 individual gas service components were screened, along with 5 process vents, 28 

engines, 7 process heaters, and 6 flare/vent systems.

The leak survey was conducted using bubble tests with soap solution, portable 

hydrocarbon gas detectors, and ultrasonic leak detectors. A screening value of 10,000 ppm or 

greater was used as the leak definition. The majority of components were screened using soap 

solution, but if a component was determined to be emitting gas, a hydrocarbon gas analyzer was 

used to determine if the component would be classified as a leaker per the above definition. Most 

leak rates were measured using a Hi-FlowTM Sampler, unless the leak was above the upper limit 

of the unit’s design (14 m3/hour). If the Hi-FlowTM Sampler could not be used, bagging or other 

direct measurement techniques were used, as appropriate. 

From the survey, approximately 2,630 of the 101,193 screened components (2.6%) were 

determined to be leaking. The study states that “components in vibrational, high-use or heatcycle gas service were the most leak prone.” The majority of the leaks were attributed to a 

relatively small number of leaking components. Table 2-12 presents the breakdown of leak

emissions by component type.

Table 2-12. Distribution of Natural Gas Emissions from Leaking Component Types

Component Type

Percent of Leak

Emissions

Valves 30.0%

Connectors 24.4%

Compressor Sealsa23.4%

Open-Ended Lines 11.1%

Crankcase Vents (on Compressors) 4.2%

Pressure Relief Valves 3.5%

Other (Pump Seals, Meters, Regulators) 3.4%
34

a

For the purposes of this paper, compressor seal emissions are not considered leaks.

The study also provided an analysis of the payback periods for fixing the identified leaks. 

That analysis is discussed in Section 3.2 of this paper.

2.12 Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five 

Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites 

(Clearstone, 2006)

This study, referred to as “Clearstone II,”11 presented the results of a comprehensive 

emissions measurement program at 5 gas processing plants, 12 well sites, and 7 gathering 

stations in the U.S. in 2004 and 2005. This work was done as follow up on a study done in 2000, 

referred to as Clearstone I, in which four gas processing plants were surveyed. (Note: one of the 

gas processing plants surveyed in the Clearstone I study was also surveyed in the Clearstone II 

study.) The work done involved a survey of all gas service equipment components at these 24 

sites. The goal was to identify cost-effective opportunities for reducing natural gas losses and 

process inefficiencies. In total, 74,438 individual components were screened.

The leak survey was conducted using bubble tests with soap solution, portable 

hydrocarbon gas detectors, and ultrasonic leak detectors. A screening value of 10,000 ppm or 

greater was used as the leak definition. The majority of components were screened using soap 

solution, but if a component was determined to be emitting gas, a hydrocarbon gas analyzer was 

used to determine if the component would be classified as a leaker per the above definition. Most 

leak rates were measured using a Hi-FlowTM Sampler, unless the leak was above the upper limit 

of the unit’s design (14 m3/hour). For consistency, both the Clearstone I and Clearstone II 

surveys used the same Hi-FlowTM Sampler. If the Hi-FlowTM Sampler could not be used, bagging 

or other direct measurement techniques were used, as appropriate.

 

11 “Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and 

Upstream Gathering Compressor Stations and Well Sites.” Prepared for the U.S. EPA under grant XA-83046001-1, 

by National Gas Machinery Laboratory, Clearstone Engineering, and Innovative Environmental Solutions, Inc.

March 2006. Note: This study, referred to as “Clearstone II”, was a follow up to a study released in 2002, referred to 

as “Clearstone I,” which surveyed four processing plants, one of which was resurveyed in Clearstone II. 
35

Secondarily to the above leak detection methodology, for all five surveys of gas 

processing plants in the study, OGI cameras were also used in order to compare the performance 

of the OGI cameras with conventional leak detection methods. Although no quantitative 

comparison was done, the study concluded that the cameras are able to screen components about 

three times as quickly as the other methods, find leaks that are inaccessible to the other methods, 

and allow for rapid leak source identification.

From the survey, approximately 1,629 of the 74,438 screened components (2.2%) were 

determined to be leaking. The study states, similarly to Clearstone I, that “components in 

vibrational, high-use, and heat-cycle gas service were the most leak prone.” Further, the majority 

of the leak emissions could be attributed to a relatively small number of the leaking components. 

Table 2-13 presents the breakdown of natural gas leak emissions by component type.

Table 2-13. Distribution of Natural Gas Emissions from Leaking Component Types

Component Type

Percent of Leak

Emissions

Open-Ended Lines 32%

Connectors 30%

Compressor Seals 20%

Block Valves 15%

Other (PRVs, Meters, Regulators, etc.) 3%

The study also provides a comparison for the one gas plant that was surveyed in both 

studies. This plant was resurveyed in order to investigate changes in its leak characteristics. It 

was noted that about 30% of the equipment components in the plant had been decommissioned 

between the surveys due to the replacement of old process units with newer ones. Generally, the 

replacement process units and equipment components had substantially reduced emission rates 

compared to the decommissioned units. The overall reduction for the new units was an 80% 

decrease in total hydrocarbon (THC) emissions compared to the old units. However, the THC 

emissions for the plant as a whole increased about 50% between the two surveys. The study 
36

gives several possible reasons for this, including the fact that the five-year timeframe between 

surveys exceeded the mean repair life for most of the components. The study also states that 

there may have been inadequate follow-up to maintenance recommendations provided during the 

first survey, as the documentation of repairs indicated it was “unclear what maintenance 

activities were undertaken in response to the Phase I survey.”

3.0 AVAILABLE EMISSIONS MITIGATION TECHNIQUES

There are a number of technologies available that can be used to identify leaks and a 

number of approaches to repairing those leaks. The technologies for identifying leaks and the 

approaches to repairing leaks are discussed in separate sections below.

3.1 Leak Detection

A variety of approaches are used for leak detection. For many 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 an analyzer, such as a TVA or an OVA. In addition, 

other monitoring tools such as OGI cameras, soap solution, acoustic leak detection, ambient 

monitors and electronic screening devices can be used to monitor process components. A 

summary of these technologies is presented below.

3.1.1 Portable Analyzers

Description

A portable monitoring instrument is used to detect hydrocarbon leaks from individual 

pieces of equipment. These instruments are intended to locate and classify leaks based on the 

leak definition of the equipment as specified in a specific regulation, and are not used as a direct 

measure of mass emission rate from individual sources. The instruments provide a reading of the 

concentration of the leak in either ppm, parts per billion (ppb), or percent concentration. For 

portable analyzers, EPA Reference Method 21 requires the analyzer to respond to the compounds 

being processed, be capable of measuring the leak definition concentration specified in the 
37

regulation, be readable to ±2.5% of the specified leak definition concentration and be equipped 

with an electrically driven pump to ensure that a sample is provided to the detector at a constant 

flow rate. 

The portable analyzers can be used to estimate the mass emissions leak rate by converting 

the screening concentration in ppm to a mass emissions rate by using the EPA correlation 

equations from the Protocol for Equipment Leak Emission Estimates (U.S. EPA, 1995). The 

correlation equations in the Protocol can be used to estimate emissions rates for the entire range 

of screening concentrations, from the detection limit of the instrument to the “pegged” screening

concentration, which represents the upper limit of the portable analyzers (U.S. EPA, 2003a). 

The portable analyzers must be calibrated using a reference gas containing a known 

compound at a known concentration. Methane in air is a frequently used reference compound. 

The calibration process also determines a response factor for the instrument, which is used to 

correct the observed screening concentration to match the actual concentration of the leaking 

compound. For example, a response factor of “one” means that the screening concentration read 

by the portable analyzer equals the actual concentration at the leak (U.S. EPA, 2003a). Screening 

concentrations detected for individual components are corrected using the response factor (if 

necessary) and are entered into the EPA correlation equations to extrapolate a leak rate 

measurement for the component (U.S. EPA, 2003a). 

Applications

The portable monitoring instruments operate on a variety of detection principles, with the 

three most common being ionization, IR absorption and combustion (U.S. EPA, 1995). The 

ionization detectors operate by ionizing the sample and then measuring the charge (i.e., number 

of ions) produced. Two methods of ionization currently used are flame ionization and 

photoionization. A standard flame ionization detector (FID) measures the total carbon content of 

the organic vapor sampled. Certain portable FID instruments are equipped with gas 

chromatograph (GC) options making them capable of measuring total gaseous non-methane 

organics or individual organic components (U.S. EPA, 1995). The photoionization detector 

(PID) uses ultraviolet light (instead of a flame) to ionize organic vapors. As with FIDs, the 

detector response varies with the functional group in the organic compounds. Photoionization 
38

detectors have been used to detect leaks in process units in the Synthetic Organic Chemical 

Manufacturing Industry (SOCMI), especially for certain compounds, such as formaldehyde, 

aldehydes, and other oxygenated compounds, which may not give a satisfactory response on a 

FID or combustion-type detector (U.S. EPA, 1995).

Nondispersive infrared (NDIR) instruments operate on the principle of light absorption 

characteristics of certain gases. These instruments are usually subject to interference because 

other gases, such as water vapor and CO2, may also absorb light at the same wavelength as the 

compound of interest (U.S. EPA, 1995). These detectors are generally used only for the detection 

and measurement of single components. For this type of detection, the wavelength at which a 

certain compound absorbs IR radiation is predetermined and the device is preset for that specific 

wavelength through the use of optical filters (U.S. EPA, 1995).

Combustion analyzers are designed either to measure the thermal conductivity of a gas or 

to measure the heat produced by combustion of the gas. The most common method in which 

portable VOC detection devices are used involves the measurement of the heat of combustion. 

These detection devices are referred to as hot wire detectors or catalytic oxidizers. Combustion 

analyzers, like most other detectors, are nonspecific for gas mixtures (U.S. EPA, 1995). In 

addition, combustion analyzers exhibit reduced response (and, in some cases, no response) to 

gases that are not readily combusted, such as formaldehyde and carbon tetrachloride (U.S. EPA, 

1995).

The typical types of portable analyzers used for detecting leaks from components are 

OVAs and TVAs. An OVA is an FID, which measures the concentration of organic vapors over 

a range of 9 to 10,000 ppm (U.S. EPA, 2003a). A TVA combines both a FID and a PID and can 

measure organic vapors at concentrations exceeding 10,000 ppm. Toxic vapor analyzers and 

OVAs measure the concentration of methane in the area around a leak (U.S. EPA, 2003a).

Screening is accomplished by placing a probe inlet at an opening where leakage can 

occur. Concentration measurements are observed as the probe is slowly moved along the 

interface or opening, until a maximum concentration reading is obtained. The maximum 

concentration is recorded as the leak screening value. Screening with TVAs and OVAs can be a
39

slow process, requiring approximately one hour for every 40 components, and the instruments 

require frequent calibration.

Costs

The costs of the portable analyzers vary based on the type of analyzer used to measure 

leak concentrations. The documentation for the EPA National Uniform Emission Standards for 

Equipment Leaks (40 CFR part 65, subpart J) provides a cost of $10,800 for a portable 

monitoring analyzer (RTI, 2011). Additional costs would also include labor costs associated with 

performing the screening and would depend on the number of components screened.

3.1.2 Optical Gas Imaging (IR Camera)

Description

Optical gas imaging (OGI) is a technology that operates much like a consumer videocamcorder and provides a real-time visual image of gas emissions or leaks to the atmosphere.

The OGI camera works by using spectral wavelength filtering and an array of IR detectors to 

visualize the IR absorption of hydrocarbons and other gaseous compounds. As the gas absorbs 

radiant energy at the same waveband that the filter transmits to the detector, the gas and motion 

of the gas is imaged. The OGI instrument can be used for monitoring a large array of equipment 

and components at a facility, and is an effective means of detecting leaks when the technology is 

used appropriately. The EPA has worked extensively with OGI technology and is in the process 

of further evaluating its capabilities. Information presented below, unless otherwise cited, is 

based on that evaluation work.

Applications

The detection capability of the OGI camera is based on a variety of factors such as 

detector capability, gas characteristics of the leak, optical depth of the plume and temperature 

differential between the gas and background. The EPA is currently studying OGI technology in 

order to determine its capabilities and limitations.

The OGI system provides a technology that can potentially reduce the time, labor and 
40

costs of monitoring components. The capital cost of purchasing an OGI system is estimated to be 

$85,000 (Meister, 2009). The ICF economic analysis estimated the capital cost of the OGI 

system to be $124,000 (ICF International, 2014). The EPA estimated that the OGI can monitor 

1,875 pieces of equipment per hour at a petroleum refinery (RTI, 2012). This study assumes for 

every hour of video footage, the operator would spend an additional 1.4 hours conducting 

activities for calibration, OGI adjustments, tagging leaks and other activities. Another estimate, 

(ICF Consulting, 2003) stated that OGI can monitor 35 components per minute (2,100 

components per hour). In comparison, the average screening rate using a handheld TVA or OVA 

is roughly 700 components per day (ICF Consulting, 2003). However, the EPA’s recent work 

with OGI systems suggests these studies underestimate the amount of time necessary to 

thoroughly monitor components for leaks using OGI technology. Additionally, the number of 

pieces of equipment that could be monitored per hour at an upstream oil and gas facility would 

likely be less than at a refinery given that equipment tends to be farther apart at these facilities 

than at a refinery. 

By increasing the number of pieces of equipment that can be viewed per hour, the OGI 

system could potentially reduce the cost of identifying leaks in upstream oil and gas facilities 

when compared to using a handheld TVA or OVA. A recent study (CL, 2013) analyzed 4,293 

leak detection surveys completed for the oil and gas industry using OGI systems. These surveys 

were completed by external contractors hired by the owner or operator of the oil and gas facility. 

This study estimated the average abatement cost to be approximately $0 per ton of VOC and 

approximately -$375 per ton of VOC for well sites and compressor stations, respectively. These 

estimates assume all leaks that are found are repaired and the recovered methane can be sold for 

$4/Mcf. The average costs of performing the OGI surveys in the study are $2,300 for a 

compressor station, $1,200 for multi-well batteries, $600 for single well batteries and $400 for 

well sites (CL, 2013). (Note: Only a prepublication draft was available of this report when the 

EPA was completing this white paper.) 

Another advantage of OGI for detecting leaks is finding leaks not directly related to 

components while in the process of surveying the overall site. Leaks such as degradation in the 

exterior of tanks or leaks in lines buried underground would be seen with OGI but very hard to 

locate with a handheld TVA or OVA.
41

For the application of this technology to this sector, the gas characteristics are well suited 

for the typical OGI camera technology because the leaks tend to be almost all methane, alkane or 

aromatics. Methane, alkanes and aromatics are all detectable due to having carbon-hydrogen 

bonds. 

OGI Operational Considerations

While the operator or inspector using OGI technology can see leaking emissions from 

equipment, quantifying the emissions is difficult. To quantify emissions with an OGI camera,

extensive metadata, such as apparent background temperature, gas leak temperature, leak size 

and wind speed must also be taken. These parameters would then be used with a developed and 

evaluated algorithm to quantify emissions. The EPA is not aware of the existence or evaluation 

of such an algorithm at this time. However, in addition to algorithms, operators can use 

quantification equipment such as a Hi-FlowTM Sampler.

The OGI system is also sensitive to the ambient conditions around the equipment that is 

being inspected. The larger the temperature differential between the leaking gas and the 

contrasting background (e.g., sky, ground or equipment), the easier the leaking gas is to see. The 

apparent temperature of the sky, a commonly used background, is also highly dependent on 

weather conditions such as cloud cover, ambient temperature and relative humidity. 

Additionally, high or variable wind conditions can reduce the optical depth and make it difficult 

for gas leaks to be identified, because the gas plume is quickly carried away from the source of 

the leak. Both these characteristics could result in operators being unable to identify leaks if the 

ambient conditions are not optimal. 

Lastly, the effectiveness of an OGI instrument is dependent on the training and expertise 

of the operator. Well-trained and experienced operators are able to detect leaks with the OGI 

system that lesser experienced operators do not detect. 

Current OGI Usage in the Oil and Gas Industry

The EPA is not aware of any studies that estimate the extent of the usage of OGI systems 

in the oil and natural gas production sector. However, certain proposed and existing regulations 

allow OGI systems as an option for fulfilling leak detection requirements, and some companies 
42

are using the technology voluntarily such as through the Natural Gas STAR program. 

Additionally, the GHGRP subpart W allows for the use of OGI technology in some 

circumstances and the Alternative Work Practice regulation (40 CFR Part 60, subpart A) allow 

the use of OGI technology along with an annual Method 21 survey as an alternative to a 

traditional leak detection and repair (LDAR) program using Method 21.

The State of Colorado recently proposed regulations that would require leak inspections 

at all well sites, compressor stations upstream of the processing plant and storage vessels. These 

proposed regulations allow OGI inspections, Method 21 or other “[d]ivision approved instrument 

based monitoring device or method” to detect leaks (CO Department of Public Health and 

Environment, Air Quality Control Commission, Regulation Number 7, Proposed November 18, 

2013). 

The State of Wyoming, as part of its permitting guidance, requires facilities with 

emissions greater than 4 tpy of VOCs in the Upper Green River Basin, the Jonah-Pinedale 

Anticline Development Area and Normally Pressured Lance to conduct quarterly leak emissions 

inspections, and OGI inspections are allowed in addition to Method 21 inspections or audiovisual-olfactory inspections (Wyoming Department of Environmental Quality, Oil and Gas 

Production Facilities, Chapter 6, Section 2 Permitting Guidance, September 2013). 

The Alberta Energy Regulator requires that a “licensee of a facility must develop and 

implement a program to detect and repair leaks.” These programs must “meet or exceed” the 

Canadian Association of Petroleum Producer’s (CAPP) best management practice (BMP) for 

leak emissions management (CAPP, 2011). The CAPP BMP allows OGI technology for 

performing these leak inspections (CAPP, 2007).

Lastly, the EPA has found that owners and operators are voluntarily using OGI systems 

to detect leaks. However, the EPA does not know the extent of these voluntary efforts within the 

industry on a national level.

3.1.3 Acoustic Leak Detector

Description
43

Acoustic leak detectors are used to detect the acoustic signal that results when 

pressurized gas leaks from a component. This acoustic signal occurs due to turbulent flow when 

pressurized gas moves from a high-pressure to a low-pressure environment across a leak opening 

(U.S. EPA, 2003a). The acoustic signal is detected by the analyzer, which provides an intensity 

reading on the meter. Acoustic detectors do not measure leak rates, but do provide a relative 

indication of leak size measured by the intensity of the signal (or how loud the sound is) (U.S. 

EPA, 2003a).

Applications

Generally, two types of acoustic leak detection methods are used; high frequency 

acoustic leak detection and ultrasound leak detection. High frequency acoustic detection is best 

applied in noisy environments where the leaking components are accessible to a handheld sensor 

(U.S. EPA, 2003a). Ultrasound leak detection is an acoustic screening method that detects 

airborne ultrasonic signals in the frequency range of 20 kHz to 100 kHz and can be aimed at a 

potential leak source from a distance of up to 100 feet (U.S. EPA, 2003a). Ultrasound detectors 

can be sensitive to background noise, although most detectors typically provide frequency tuning

capabilities so that the probe can be tuned to a specific leak in a noisy environment (U.S. EPA, 

2003a).

A URS Corporation/University of Texas at Austin (URS/UT) study described a “throughvalve acoustic leak detection device” or VPAC that was used to measure leaks at six sites (four 

gathering/boosting stations and two natural gas processing plants) (URS/UT, 2011). Leak 

measurements were made using the VPAC device and high volume sample to compare the 

readings from the two devices. The study authors found that there was no statistically 

significant correlation between the VPAC and the direct flow measurements, and the study 

authors determined that the VPAC method was not considered to be an accurate alternative to 

direct measurement for the sources tested (URS/UT, 2011).

Costs

No cost data for acoustic leak detectors were available in the studies or research 
44

documents.

3.1.4 Ambient/Mobile Monitoring

Description

A growing number of research and industry groups are using mobile measurement 

approaches to investigate a variety of source emissions and air quality topics. For oil and natural 

gas applications, a vehicle can be equipped with at minimum a methane measurement instrument 

and GPS to facilitate discovery of previously unknown sources and in more advanced forms, 

provide information on source emission rates.

Applications

Mobile leak detection techniques sample emission plumes from stand-off (sometimes 

offsite) observing locations and are, therefore, generally less accurate than direct (onsite) source 

measurements. Mobile leak detection techniques can cover large survey areas and can be 

particularly useful in identifying anomalous operating conditions (e.g., pipeline leaks and well 

pad malfunctions) in support of onsite OGI and safety programs. All mobile techniques require 

downwind vehicle access and favorable wind conditions for plume transport to the observing 

location. The presence of trees or other obstructions can limit the efficacy of mobile leak 

detection techniques and in some cases prevent the application of remote source emission rate 

assessment.

Mobile leak detection instrument packages require some expertise for operation, 

especially in source emission rate measurement applications. Additionally, while mobile leak 

detection techniques can detect emissions around a site, such as a well site or gathering station, it 

cannot necessarily pinpoint the equipment that is the source of those emissions. Mobile leak 

detection techniques might be best used in conjunction with OGI technology; an OGI inspection 

would be triggered by the detection of above normal emissions by the mobile leak detection 

technique. In conversations with operators of upstream oil and natural gas facilities, the EPA has 

discovered that some companies are voluntarily using this two-phase approach to detect and then 

pinpoint VOC and methane leaks. It is believed that future forms of mobile leak detection 
45

techniques for the oil and gas sector may include lower cost, work truck-mounted systems that 

provide fully autonomous detection capability for anomalous emissions in support of such an

onsite OGI inspection (Thoma, 2012).

An example of a mobile leak detection technique applicable to the upstream oil and gas 

sector is being developed under the EPA’s Geospatial Measurement of Air Pollution (GMAP) 

program (Thoma, 2012). The near-field OTM 33A produces a 20-minute “snapshot” measure of 

emissions from near ground level point sources at observation distances of approximately 20 to 

200 m. With strict application and favorable conditions, this type of point sensor-based remote 

measurement has source emission rate measurement accuracies in the ± 30% range with 

ensemble averages achieving accuracies within ± 15% by reducing random error effects.

Although future, fixed deployment, low cost sensor systems may provide long-term emission 

level monitoring capability for oil and gas production sites,

12 current mobile assessment 

approaches can only provide a “snapshot” of emissions. Because some oil and gas upstream 

sources possess significant temporal and seasonal variability, the short-term nature of 

observation must be considered to avoid error in exportation of instantaneous emissions (e.g., to 

tons per year estimates). Results of well pad measurements from multiple oil and gas fields using 

mobile measurement are presented in Section 2.

Costs

Current mobile measurement instrument packages can range in cost from approximately 

$20,000 - $100,000 depending on the capability of the package.

3.2 Repair

After a leak is detected, the owner or operator of the facility must decide whether or not 

to fix the leak, unless they are required to fix the leak due to regulatory or permitting obligations.

 

12 A collaborative request for proposal (RFP) was released in the spring of 2014 by Apache Corporation, BG Group, 

EDF, Hess Corporation, Noble Energy, and Southwestern Energy called the “Methane Detectors Challenge: 

Continuous Methane Leak Detection for the Oil and Gas Industry.” The “Challenge” is “designed to spur the 

development of cutting-edge, new technologies that provide continuous detection of methane emissions.” Available 

at: http://www.edf.org/energy/natural-gas-policy/methane-detectors-challenge
46

This decision can be based on several factors, including, the cost of fixing the leak and the size 

of the leak. A number of studies discuss costs and effectiveness of various leak repair options.

3.2.1 Quantifying Cost-Effectiveness of Systematic Leak Detection and Repair Programs 

Using Infrared Cameras (CL, 2013)

This study, discussed previously in Section 2, provided an analysis of the net present 

values (NPVs) of repairing all of the identified leaks in the surveys using the estimated repair 

cost and the value of the recovered gas. The study found that over 90% of gas emissions from 

leaks can be repaired with a payback period of less than one year, assuming a value of $3 per 

thousand cubic feet ($/Mcf) for the recovered gas. However, when compared with the cost of the 

monitoring (estimated to be $600 to $1,800 per facility), the economic benefits of repairing the 

leaks at most facilities are less than the total cost of the survey. For well sites and well batteries, 

the study estimated that 1,424 of the sites (81%) had a negative NPV, which averaged -$1,160 

per facility. However, when the all of the individual well sites and well batteries are aggregated 

into a group, the aggregated NPV is positive, which suggests that a minority of sites have high 

leak rates and, thus, a positive NPV for monitoring and fixing leaks. These sites skew the mean 

NPV to a positive value.

The study also analyzed two alternative repair strategies: only repair leaks that are 

economic to repair (e.g., NPV > 0 for the repair) or repair of leaks that exceeded a certain 

threshold (e.g., 20 thousand cubic feet per year (Mcf/yr)). A summary of the findings for each of 

the scenarios is provided in Table 3-1.

Table 3-1. Comparison of Three Hypothetical Repair Strategies for Multi-Well Batteriesa

Category Repair all leaks

Repair leaks 

with a NPV>0

Repair leaks

> 20 Mcf

Potential leak reductions after survey 94.5% 92.6% 88.1%

Methane abatement cost ($/ton CO2e) 1 0.8 1.7

VOC abatement cost ($/ton VOC) 46 41 79

Average number of leaks to repair 3.8 3.5 2.9

a - Derived from Table 3 (CL, 2013).
47

The study concludes that the potential leak reductions after survey, methane abatement 

cost, VOC abatement cost, and average number of leaks to repair are similar under each of the 

three strategies. The study authors conclude that the results are similar because once a leak is 

found it is almost always economic to repair it.

The study also provided costs of repair and leak detection based on the survey data. The 

average cost of hiring an external service provider to perform a survey using OGI technology

was determined to be $1,200 for multi-well batteries, $600 for single well batteries, and $400 for 

a well site. The range of costs of repair for well sites is shown in Table 3-2.

Table 3-2. Total Average Leak Rate and Repair Costs by Components at Well Sites

Component

Leak rate 

(cfm)

Repair Costs

Minimum Average Median Maximum

Connector/Connection 0.11 $15 $56 $50 $5,000

Instrument Controller 0.03 $20 $129 $50 $2,000

Valve 0.04 $20 $90 $50 $5,500

Open-Ended Line 0.02 ---

b

---

b

---

b

---

b

Regulator 0.02 $20 $189 $125 $1,000

a - Derived from Tables 6 and 7 (CL, 2013).

b – Repair costs for open-ended lines were not provided in the document.

3.2.2 Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas 

Processing Plants (Clearstone, 2002)

The Clearstone I study, discussed in Section 2, provided analysis of the payback periods 

for fixing the identified leaks, and what level of emission reductions could be achieved. Overall, 

the study estimated that up to 95% of total natural gas losses can be reduced cost-effectively 

(assumed gas price of $4.50 per Mcf), which corresponds to methane reductions of nearly 80%. 

The study also presents scenarios where only those reduction opportunities having a certain 

payback period (e.g., 6 months or 1 year) are implemented. For those cases, the estimated 
48

percent of total natural gas loss reduction and corresponding reductions in methane are presented 

in Table 3-3. One caveat from the study is that the payback periods do not take into account the 

cost of the leak detection survey, only factoring in cost of repair and benefit of the gas captured.

Table 3-3. Achievable Emission Reduction Percentages for Given Positive Payback Periods

Emission Type Reduction

Payback Period

< 6 months < 1 year < 2 years < 4 years

Natural Gas 78.8% 92.3% 93.1% 94.9%

Methane 71.9% 78.1% 79.2% 79.5%

The study estimated that implementing all of the cost-effective repair opportunities 

identified would result in gross annual cost savings of approximately $1.1 million across the 

plants in the study (based on a gas value of $4.50 per Mcf). This amounts to over 50% of total 

cost-effective loss reduction opportunities identified for all emission sources (leaks, flaring, 

combustion equipment, and storage tanks) at the plants, and results in an average annual net 

savings of approximately $280,000 per site (the site-specific values range between $180,000 and 

$330,000).

3.2.3 Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas 

Processing Plants and Upstream Gathering Compressor Stations and Well Sites (Clearstone, 

2006)

The Clearstone II study, discussed in Section 2, analyzed the cost-effectiveness of 

repairing the leaks identified in the surveys that were performed. The study estimated that up to 

96.6% of total natural gas losses could be reduced cost-effectively (assuming a gas price of $7.15 

per Mcf), which corresponds to methane reductions of 61%. The study also estimated that the 

average annual lost gas values from the sites surveyed were $536,270 per gas plant, $49,018 per 

gathering station, and $3,183 per well site.

This study also provided the base repair cost and mean repair life for 16 types of 

components. The values for several of the more common components reported in the study are 

summarized in Table 3-4.
49

Table 3-4. Basic Repair Costs and Mean Repair Life for Several Common Leaking 

Components

Component Type

Basic Repair Costs Mean Repair 

Low High Life (years)

Compressor Sealsa$2,000 $2,000 1

Flanges $25 $400 2

Open-End Lines $60 $1,670 2

Pressure Relief Valves $79 $725 2

Threaded Connections $10 $300 2

Tubing Connections $15 $25 4

Valves $60 $2,229 2 - 4

Vents $2,000 $5,000 1

a

For the purposes of this paper, compressor seal emissions are not considered leaks.

3.2.4 Natural Gas STAR Directed Inspection and Maintenance (U.S. EPA, 2003a, U.S. EPA, 

2003b, and U.S. EPA, 2003c)

For detecting and repairing leaks, the Natural Gas STAR program recommends 

implementation of a DI&M program to economically reduce methane emissions from leaking 

components (U.S. EPA, 2003a, U.S. EPA, 2003b, and U.S. EPA, 2003c). A DI&M program, 

which can be implemented at any facility in the upstream or downstream sector of the industry, 

starts with a comprehensive baseline emissions survey. This survey involves screening all of the 

components at the facility to identify the leaking components, as well as measuring the identified 

leaks to determine emission rates. Determining an emissions rate is an important step that allows 

the economic evaluation of mitigation techniques. Natural Gas STAR partners have reported 

using OGI technology to effectively scan large numbers of components in a short span of time. 

The choice of leak detection equipment typically depends on the number of components to be 

scanned. Optical gas imaging technology is popular at facilities that have thousands of 
50

components, such as at processing plants. From previous field studies conducted by the EPA and 

Natural Gas STAR partners, the EPA has observed that typically 20% of the top leaking 

components account for approximately 80% of the emissions from a facility. This provides a 

strong basis to conduct DI&M at facilities because fixing a small number of leaks can 

significantly reduce the total leak emissions from a facility.

Once the leaking sources have been identified, the next step recommended is the 

economic analysis of mitigation techniques. The estimated repair costs for the identified leaks 

can be compared to the potential savings from fixing the leaks based on the value of natural gas, 

and the leaks that are determined to be economical to fix by the owner can be repaired. 

Not all leaks identified can be fixed immediately. For example, leaks on a flange on a 

transmission pipeline cannot be fixed without shutting down the system and purging the pipeline 

of all the natural gas. The identification of leaks before a shutdown through a DI&M program 

helps facilities focus on specific areas during a shutdown cycle. Shutdown cycles are usually 

short, lasting from a day up to a week. 

The Natural Gas STAR program also lists average emission rates, repair cost ranges, and 

payback periods for fixing leaks at several different facilities. Tables 3-5 and 3-6 show the 

emission rates and repair costs for several common leaking components at gas processing plants, 

transmission compressor stations, and gate stations.
51

Table 3-5. Total Average Leak Rate and Repair Costs by Component at Processing Plants

Component

Average Component Leak Rate by Location 

(Mcf/yr)

Average Repair 

Cost

NonCompressorReciprocating 

Compressor

Centrifugal 

Compressor

Connections 6.7 - - $25

Flanges 88.2 89.7 115 $150

Pressure Relief Valves 3.9 308 - $150

Other Valves 25 127 63.4 $130

Compressor Seala- 1,440 485 $2,000

Open-Ended Line (OEL) 43 - - $65

Compressor Blowdown OEL - 1,417 2,887 $5,000

Note: Adapted from exhibit 5 in “Directed Inspection and Maintenance at Gas Processing Plants and Booster 

Stations” Lessons Learned document. Available online: http://epa.gov/gasstar/documents/ll_dimgasproc.pdf

a

For the purposes of this paper, compressor seal emissions are not considered leaks.
52

Table 3-6. Total Average Leak Rate and Repair Costs by Component at

Compressor Stations

Component

Average Component Leak Rate by 

Location (Mcf/yr) Average Repair Costs

On Compressor Off Compressor Low High

Ball/Plug Valves 0.64 5.33 $40 $120

Blowdown Valve - 207.5 $200 $600

Compressor Valve 4.1 - $60 $60

Unit Valve - 3,566 $70 $2,960

Flange 0.81 0.32 $300 $1,250

Open-Ended Line - 81.8 $45 $45

Pressure Relief Valve - 57.5 $1,000 $1,000

Connection 0.74 0.6 $10 $30

Note: Adapted from exhibits 4 and 5 in “Directed Inspection and Maintenance at Compressor Stations” Lessons 

Learned document. Available online: http://epa.gov/gasstar/documents/ll_dimcompstat.pdf.

3.2.5 Update of Fugitive Equipment Leak Emission Factors (CAPP, 2014)

In February of 2014, CAPP issued a report on emission factors for leaks at upstream oil 

and gas facilities in Alberta and British Columbia. This report served as an update to similar 

factors that were developed in 2005, prior to the implementation of DI&M BMPs in both these 

provinces. The report compares the 2005 leak emission factors to the 2014 leak emission factor 

in order to draw conclusions regarding the effectiveness of the DI&M BMPs in Alberta and 

British Columbia.

Leak survey results provided by eight industry participants in Alberta and British 

Columbia were the basis of the emission factors. The results came from 120 facilities and 

included approximately 276,947 components. All surveys were conducted after 2007. The study 

authors used this data to develop average emission factors for each type of component and then 
53

compared those factors to the factors developed in 2005. Table 3-7 provides a comparison of the 

emission factors for each type of component from the 2005 study and the 2014 study.

Table 3-7. Comparison of Total Hydrocarbon Leak Emission Factors for Upstream Oil and 

Gas Facilities that have Implemented DI&M BMPs

Sector Component Servicea

2014 

Emission 

Factor 

(kg/hour)

2005 

Emission 

Factor 

(kg/hour)

Ratio of 2014 

to 2005 

Emission 

Factors

Gas Compressor Sealb GV 0.04669 0.71300 0.065

Gas Connector GV 0.00082 0.00082 1.000

Gas Connector LL 0.00016 0.00055 0.298

Gas Control Valve GV 0.03992 0.01620 2.464

Gas Open-Ended Line All 0.04663 0.46700 0.100

Gas Pressure Relief 

Valve All 0.00019 0.01700 0.011

Gas Pump Seal All 0.00291 0.02320 0.125

Gas Regulator All 0.03844 0.00811 4.740

Gas Valve GV 0.00057 0.00281 0.205

Gas Valve LL 0.00086 0.00352 0.245

Oil Compressor Seal GV 0.01474 0.80500 0.018

Oil Connector GV 0.00057 0.00246 0.232

Oil Connector LL 0.00013 0.00019 0.684

Oil Control Valve GV 0.09063 0.01460 6.207

Oil Open-Ended Line All 0.15692 0.30800 0.509

Oil Pressure Relief 

Valve All 0.00019 0.01630 0.012

Oil Pump Seal All 0.00230 0.02320 0.099

Oil Regulator All 0.52829 0.00668 79.085

Oil Valve GV 0.00122 0.00151 0.809

Oil Valve LL 0.00058 0.00121 0.479

Note: Adapted from Table 10 in “Update of Fugitive Equipment Leak Emission Factors” document (CAPP, 2014). 

Available online: http://www.capp.ca/getdoc.aspx?DocId=238773&DT=NTV

a GV = Gas/Vapor, LL = Light Liquid

b

For the purposes of this paper, compressor seal emissions are not considered leaks.
54

The study authors conclude that emissions from leaks have decreased 75% among the 

survey participants since the implementation of the DI&M programs in Alberta and British 

Columbia. The leak factors for almost all categories of equipment decreased. The authors did not 

use this data to develop national or regional estimates of total leak emissions.

4.0 SUMMARY

The EPA has used the information presented in this paper to inform its understanding of leak

emissions and potential techniques that can be used to identify and mitigate leaks in the oil and 

natural gas production, processing, transmission and storage sectors. The following are 

characteristics the Agency believes are important to understanding this source of VOC and 

methane emissions:

 The 2014 GHG Inventory estimates there are approximately 332,662 MT of potential 

methane leak emissions from gas production, 33,681 MT of potential methane leak 

emissions from gas processing, and 114,348 MT of potential methane leak emissions gas 

transmission.

 Several studies suggest that the majority of methane and VOC emissions from leaks 

come from a minority of components (CL, 2013; Clearstone, 2002; and Clearstone, 

2006). Furthermore, one study concludes that the majority of methane and VOC 

emissions from leaks come from a minority of sites (CL, 2013). One study found that the 

majority of leak emissions from these sites may be attributed to maintenance-related 

issues such as open thief hatches, failed pressure relief valves, or stuck dump valves

(Thoma, 2012).

 The methane and VOC leak emissions from well sites depend on a number of different 

factors including: the number of wells located at the site, the number of compressors 

located at the well site and the number and type of processing equipment (separators, 

heaters, etc.) used at the site.

 Currently, portable analyzers provide an effective approach for both locating and 

measuring the concentration of leaks from oil and natural gas production sites. 

 There are several other technologies being used to detect leaks for the oil and natural gas 

sectors. These technologies include OGI and ambient/mobile monitoring.
55

 OGI is being increasingly used to locate leaks in the oil and gas industry. The technology 

can potentially provide a more time and cost efficient method for locating leaks than 

traditional technologies, such as portable analyzers. However, there may be limitations to 

this technology.

o The technology must be used methodically in order to address certain limitations, 

such as sensitivities to ambient conditions. 

o OGI technology does not quantify emissions. It may be possible to develop 

algorithms to quantify emissions with data from OGI, but, to the EPA’s 

knowledge, such algorithms are not currently available.

 Ambient/mobile monitoring and OGI technology might be most effective when used in 

tandem. In such cases, an OGI inspection could be triggered by the detection of above 

normal emissions by the ambient/mobile monitoring equipment. This approach 

potentially could reduce or eliminate OGI inspections at facilities with minimal leak 

emissions.

 Available information suggests that once a leak is found it is almost always economical 

to repair the leak. According to the studies reviewed, the cost of detecting the leak is 

generally far larger than the cost of fixing the leak.

 The CAPP 2014 study and experience through the Natural Gas STAR program suggest 

DI&M programs can effectively decrease leak emissions.

5.0 CHARGE QUESTIONS FOR REVIEWERS

1. Did this paper appropriately characterize the different studies and data sources that quantify 

VOC and methane emissions from leaks in the oil and natural gas sector? 

2. Please comment on the approaches for quantifying emissions and on the emission factors 

used in the data sources discussed. Please comment on the national estimates of emissions 

and emission factors for equipment leaks presented in this paper. Please comment on the 

activity data used to calculate these emissions, both on the total national and regional 

equipment counts.

3. Are the emission estimating procedures and leak detection methods presented here equally 

applicable to both oil and gas production, processing, and transmission and storage sectors?
56

4. Are there ongoing or planned studies that will substantially improve the current 

understanding of VOC and methane emissions from leaks and available techniques for 

detecting those leaks? Please list the additional studies you are aware of.

5. Are there types of wells sites, gathering and boosting stations, processing plants, and 

transmission and storage stations that are more prone to leaks than others? Some factors that 

could affect the potential for leaks are the number and types of equipment, the maintenance 

of that equipment, and the age of the equipment, as well as factors that relate to the local 

geology. Please discuss these factors and others that you believe to be important.

6. Did this paper capture the full range of technologies available to identify leaks at oil and 

natural gas facilities?

7. Please comment on the pros and cons of the different leak detection technologies. Please 

discuss efficacy, cost and feasibility for various applications.

8. Please comment on the prevalence of the use of the different leak detection technologies at 

oil and gas facilities. Which technologies are the most commonly used? Does the type of 

facility (e.g., well site versus gathering and boosting station) affect which leak detection 

technology is used?

9. Please provide information on current frequencies of revisit of existing voluntary leak 

detection programs in industry and how the costs and emission reductions achieved vary with 

different frequencies of revisit.

10. Please comment on the potential for using ambient/mobile monitoring technologies in 

conjunction with OGI technology. This would be a two-phase approach where the 

ambient/mobile monitoring technology is used to detect the presence of a leak and the OGI 

technology is used to identify the leaking component. Please discuss efficacy, cost and 

feasibility.

11. Please comment on the cost of detecting a leak when compared to the cost to repair a leak. 

Multiple studies described in this paper suggest that detecting leaks is far more costly than 

repairing leaks and, due to generally low costs of repair and the subsequent product recovery, 

it is almost always economical to repair leaks once they are found. Please comment on this 

overall conclusion.
57

12. If the conclusion is correct that it is almost always economical to repair leaks once they are 

found, then how important is the quantification of emissions from leaks when implementing 

a program to detect and repair leaks?

13. Please comment on the state of innovation in leak detection technologies. Are there new 

technologies under development that are not discussed in this paper? Are there significant 

advancements being made in the technologies that are not described in this paper?

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