# Oil and Natural Gas Sector Leaks

Re p or t f o r O il and N atural G as Sector Leak s R e v i e w P a n e l April 2014

P r e p a r e d by
U

. S. E PA O f

f i c e o f A i r Q u a l i t y P l a nn i ng a n d S t a n d a r ds ( O A Q PS)

T h i s i n f or m a ti on i s d

i s t r i b u t e d so l e l y f or t h e p u rpose of pr e - d

i ss e m i n a ti on p ee r r

ev i e w u n d

e r a p p li c ab l e i n f or m a ti on q u a lit

y g u i d e li ne s. I t h as n ot b ee n f

or m a ll y d i ss e m i n a t e d by E P A . It do e s n ot r

e pr e s en t a n d

s h o u l d n ot be c o n s t

r u e d t o r e pr e s en t a n y A g enc y d e t e r m i n a ti on or po li cy .iiiii



### 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 )

................................ ................................ ................................ .......... 34iv

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 M onitoring

................................ ................................ .. 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

................................ ................................ ................................ ............... 571



### PREFACE

On March 28, 2014 the Obama Administration released a key element called for in the President’s Climate Action Plan: a Strategy t o 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 signi ficant sources of methane and volatile organic compounds (VOCs) in the oil and gas sector, covering emissions and mitigation techniques for both pollutants. The
A gency is seeking input from independent experts, along with data and technical information
fro m 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.

T he white papers are available at: www.epa.gov/airquality/oilandgas/whitepapers.html2



### 1.0 INTRODUCTION

The oil and natural gas exploration and production industry in the U.S. is highl y 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, 201 2a), and an estimated 536,000 producing oil wells in the U.S. in 2011 (U.S. EIA, 2012b). I t is anticipated that the number of gas and oil
wells will continue to increa se substantially in the future because of the continued and expanding
use of horizontal d rilling 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 cle ar 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 emission s 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, 2013 b ) and crude oil and natural gas liquids are projected to increase by approximately 25 % through 2019 (U

. S

. EIA, 2013 b )

. According to the U.S. Energy Information Administration (EIA), over half of new oil wells drilled co

- produce natural gas (U

. S

. EIA, 2013 a )

. The projected growth is primarily led by the increased development of shale gas, tight gas, and coalbed methane resources utilizing new productio n 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 leak s 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 VOC s

. The proportion of the different types of air3

emissions is affected by the composition of the gas in t he 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, open

ended lines, pressu re relief devices, pump seals, valves, and improperly controlled liquids storage. 1 For 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. T he 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 Secti on 2 the definition each study uses is compared to the definition presented here.

L eak 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 goo d 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 improp erly 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 c an 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
incl udes available emission data, estimates of VOC and methane emissions and available mitigation techniques . Section 2 of this document describes the EPA’s understandin g 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 underst anding 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 te chniques

.



### 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 studie s 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 port ions 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 sector s

. Some of these studies are listed in
Table 2

- 1, along wit h an indication of the type of information contained in the study (i.e., activity level).5

Table 2

- 1. Summary of Major Sources of Leaks Emissions Information

Name Affiliation Year of Report Activity Factor Protocol for Equipment Leak Emission Estimat es (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 R eporting Program (U

. S

. EPA, 2013 ) U

. S

. Environmental Protection Agency 2013 Facility

Inventory of Greenhouse Ga s Emissions and Sinks: 1990

- 2012 (U

. S

. EPA, 201 4 ) U.S.

Environmental Protection Agency 201 4 Regional

Measurements of Methane Emissions at Natur al 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 o f Well Pad Emissions in Greeley, CO (Modrak, 2012) ARCADIS/Sage Environmental Consulting/U.S. Environmental Protection Agency 2012 Colorado

Quantifying C ost

E ffectiveness of S ystematic Leak Detection and Repair Programs U sing Infrared C ameras (CL, 2013) C arbon 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 i n the U.S. Onshore Oil and Natural Gas Industries (ICF International , 2014) ICF International 2014 Nationwide6 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 m ethane 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 n ot as well represented.

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

The EPA protocol provide s standard procedures for estimat ing the total organic compound mass emissions from leaks at oil and natural gas production facilities. Th e protocol provide s 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 g as 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, fl anges, 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 2 and 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 Emission7

production facilities collected by the American Petroleum Institute

. 3 , 4 The emissions calculated
from these emission factor s 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 mas s 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 line s ) and service (e.g., gas, heavy oil, light oil, and water/oil) at th e 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 ” equipmen t type emission
factor that was derived f

or 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 th an or equal to 10,000 parts per million (ppm) and the number of components with a l eak 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).

Th is screening range approach is a better indication of the actual leak rate from individual equipment tha n 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 measu red 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 of fers 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 ind ustry apply to refineries, marketing
terminals and oil and gas production operations. The petroleum industry correlation equation s 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 devic e. 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 pe gged 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 thi s prediction to be incorrect (U

. S

. EPA, 1995), because m ass 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 th at 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 co rresponding 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 In dustry, 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 compon ents and the average number of components per facility to estimate10

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 appro aches to estimate component emissions for the onshore natural

gas production , offshore natural gas production, natural gas processing, natural gas transmission and natural gas storage sector s

. The first approach involved screening components using a portab le 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, pum ps, 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 fl anges and threaded unions (all services)

 Open

- Ended Lines (all services)

 Sampling Connections (all services)
All components associated with an equipment source or facility w ere 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 flam e ionization detector (FID) was11

used for conducting the screening meas urements. 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

- Flow TM (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

est imates derived from this method will not be discussed further.

For onshore natural gas production, t he facilities were broken up into two categories; eastern natural gas production and western gas production to account for regional differences in
the meth ane 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 on shore 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 discu ssed in more detail
in Section 2.1.4.

As shown in the table s , 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 y ear. This converts to approximately 292,930 metric tons (M T ) 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

Equipmen t 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%

Sepa rator 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 Compressors c 87,334 16,915 1,477 27,895 93%

Lg Gathering Compressors d 55 2,000 96 53.0 1,001 136%

Gathering Stations e 1,940,487 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 dens ity 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 fa ctor 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 c ounts 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 w ere estimated to be 0.538 MMscf/yr ( 1 0.2 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 % r eciprocating 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 Pro ce ssing Plants in the United States (1992 Base Year) a

Equipment Average Facility Methane Emissions ( MM scf/yr) Activity

Factor, Number of Plants/ Compressors Annual

Methane Emissions (MMscf) Annual

Methane Emissions (MT) b 90%

Confidence Interval

Gas Process ing Plant c 2.40 726 1,744 32,925 27%

Reciprocating Compressors d 0.538 4,092 2,201 41,571 36%

Centrifugal Compressors e 0.031 726 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 calculate d 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 compre ssor 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 (FER C). 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 estim ated 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 emissio ns 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 Natio nal Annual Emission Estimate for Natural Gas Transmission

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

Equipment Average Facility Methane Emissions ( MM scf/yr) Activity

Factor, Number of Stations/ Compressors Annual

Methane Emissions (MMscf) Annual

Methane Emissions (MT) b 90%

Confidence Interval
Compressor Stations c 1.94 1,700 3,298 62,276 103 %

Reciprocating Compressors d 0.552 6,799 3,753 70,869 68 %

Centrifugal Compressors e 0.018 681 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 includ e 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 ga s 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 centri fugal 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 met hane 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 Nati onal Annual Emission Estimate for Natural Gas Storage Facilities in the United States (1992 Base Year) a

Equipment Average Facility Emissions ( MM scf/yr) Activity

Factor, Number of Facilities / Compressors Annual

Methane Emissions (MMscf) Annual

Methane Emis sions (MT) b 90%

Confidence Interval
Storage Facilities c 6.80 475 3,230 61,004 100

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

Reciprocating Compressors d 0.47 1,396 656 12,390 80

Centrifugal Compressors e 0.017 136 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 Systems 5 collected 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
, a s facilities are required to su bmit annual reports only if total GHG emissions are 25,000 metric tons carbon dioxide equivalent (CO 2 e) or more. Facilities use uniform methods prescribed by the EPA to calculate GHG emissions, such as direct measurement, engineering calculations, or emiss ion 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 4 0 CFR Part 98 , s ubpart W.17

Methods for calculating emission s from leaks depend on the industry segment. Facilities in the onshore petrole um 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, com pressors, in

- line heaters, dehydrators, heater

- treaters, and headers) multiplied by average component counts specified in the s ubpart W regulations
, or (2) a count of each component individually for the facility. Emissions are then calculated by multiplyin g population count by the appropriate population emission factor specified in the s ubpart W regulations.

Facilities in the onshore gas processing and gas transmission segments use counts of
l eak ing components and leak emission factors for calculating emiss ions from leaks. The count s of leaking components are identified during an annual leak survey using an optical gas imaging ( OGI ) instrument , EPA Method 21 , i nfrared (IR) laser beam illuminated instrument , or an

a coustic leak detection device

. Once the leak ing 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, repo rted 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 Emissi ons and Sinks: 1990

- 201 2 (U.S. EPA, 201 4 )

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 tim e series, beginning with 1990. The U.S.
submits the GHG I nventory 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 s ystems (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 tr ansport hydrocarbon18

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 estimate s for gas wells, separation equipment, gathering compressors, gathering pipelines, drilling and well completion s , normal operations, condensate tank vents, well workovers, liquids unloading, vessel blowdowns
, and process upsets.

For the natural gas produ ction 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 system s include reciprocating compressors, equipment such as scrubbers and coolers associated with the compressors, and the piping. Lea ks 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 compres sor seals in the GHG Inventory. (Note: V ented emissions from compressors are not defined as leaks in this paper
, b u t a r e d i s c u s s e d i n t h e w h i t e p a p e r o n c o m p r e s s o r s .) The 201 4 GHG Inventory (published in 201 4 ; containing emissions data for 1990

- 201 2 ) calculates potential 6 methane leak emissions from gas
well s 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 201 4 GHG Inven tory for each of the NEMS region s 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 201 4 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

r eductions 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 si nce 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 composition 7 to 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

ea ch year of the GHG I nventory. Because component counts are not available for each year of
the GHG I nventory, a set of i ndustry activity data drivers wa s developed and used to update activity data

. 8 The 201 4 GHG Inventory , emission factors, and methane emissions are presented by region in Table 2

- 6

. The 201 4 GHG Inventory estimated 33 2 , 662 MT of potential methane
leak emiss ions from gas wells and field separation equipment from natural g as production
activities in 2012

.

Table 2

- 6 . 2011 Data and Calculated Methane Potential Leak Emissions for the Natural Gas Production Segment by Region a

Region Activity Activity Data Emis sion 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 W ells with Hydraulic Fracturing 46,367 7. 5 4 scfd/well 2,457

Heaters 318 15.38 scfd/heater 34
Separators 112,872 0. 9 7 scfd/separator 771

Dehydrators 22,164 2 3.53 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 o f 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 u sed 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 Emis sion 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 W e lls with Hydraulic Fracturing 30,156 8.35 scfd/well 1,771

Heaters 43,869 14.9 scfd/heater 4,596
Separators 47,003 0.9 4 scfd/separator 311

Dehydrators 15,064 95.54 scfd dehydrator 10,118

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

Rocky M ountain Associated Gas

Wells 32,598 NA NA

Non

- associated Gas Wells 9,665 35. 05 scfd/well 2,381

Gas W ells 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 W ells 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. 1 1 scfd dehydrator 3,786

Meters/Piping 55,885 54.06 scfd/meter 21,23721 Region Activity Activity Data Emis sion 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 W ells 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. 9 6 scfd/well 1,512

Gas W ells with Hydraulic Fracturing 49,862 7. 9 6 scfd/well 2,789

Heaters 17,222 64. 60 scfd/heater 7,821

S eparators 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, 201 4 ).

The gas processing and gas transmission segments are not broken into regions like the gas production segment in the 201 4 GHG Inventory. Instead
, these segments provide national
level emission estimates for their individual emission sources. For both s egments, 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 201 4 GHG Inventory
calculates potential methane emissions from these s ources 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 applying22

the emission factors to activity cou nts (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 I nventory, a set of industry activity data
drivers wa s developed and used to update activity data

. 9 The 20 1 4 GHG I nventory gas processing and gas transmission sources , emission factors, and methane emissions are presented
in Table 2

- 7

. For 201 2 , the 201 4 GHG I nventory estimated 3 3, 6 8 1 MT of potential methane
emissions from gas processing leak emissions and 1 1 4 , 3 4 8 MT of potential methane emissions
from gas transmission l eak emissions.

Table 2

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

Gas Processing and Natural Gas Transmi ssions Segments a

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, 201 4 ).

For 201 2 , the 201 4 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 m ethane emissions from oil and gas.

2.5 Measurements of Methane Emissions at Natural Gas Produc tion Sites in the United
States (Allen et al., 2013)

A study completed by multiple academic institutions and consulting firms was conducted to gather methane emis sions data at onshore natural gas sites in the U

. S

. This study used direct

9 For exampl e, 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 transmi ssion) 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 co vered 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 Sampler

TM 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 coll ected 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 instrum ent , was the methane flow.

Table 2

- 8. Summary of Emissions from Leaks

Emissions Per Well a

Appalachian Gulf Coast Midcontinent Rocky Mountain All Facilities
Number of S ites with W el l s V isited ( n umber of wells with leaks detected) 47 (30) 54 (31) 26 (1 9) 19 (17) 146 (97)

Methane Emission Rate (scf/min/well) 0.098 ± 0.059 0.0 52 ± 0.0 30 0.0 46 ± 0.0 24 0.0 35 ± 0.0 26 0.0 64 ± 0.0 23

Whole Gas Emissions Rate (based on site specific gas composition) (scf/min/well) 0. 100 ± 0.0 60 0.0 5 8 ± 0.0 33 0.0 55 ± 0.0 34 0.0 4 7 ± 0.0 34 0.0 70 ± 0.0 24

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

The study authors concluded t he average values of leak emissions per well reported in
Table 2

- 8 are comparable to the a verage 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 Inven tory 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 o f 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 level s?

 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 perform ed 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 O GI came ra, a toxic vapor analyzer (TVA), a H i

- F low
S ampler TM 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 wer e 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 H i

- F low S ampler TM to measure the volumetric flow rate of the leak. Gas samples from sel ected 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 pads25

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 summa ry 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 valve s, 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 cont rollers, instrumentation, regulators, gauges, and vents.

Table 2

- 9 . Average and Maximum Point Source Emission Rates by Site Type a

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

Average Maximum Average Maximum

Well Pad 16 445 0.07 8.6

Well Pad with Compres sor(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 Type a

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 37 5 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 37 5 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 we ll 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 classifie d as tank
leaks.

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

An onsi te direct measurement study of emissions from 23 well pads in areas near27

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 procedu res ( 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 t hree major differences in the studies.

 The City of Forth Worth Air Quality S tudy was con ducted 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 high er methane to VOC ratio compared to an emission in a wet gas area.

 T he 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, mos t storage tanks contained produced water and were not controlled.

 T he City of Fort Worth Air Quality S tudy used the EPA Compendium M ethod TO

- 15
and ASTM 1 945 (for methane) for source canister analysis
, whereas the Greeley study
used the Ozone Precursor me thod (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 i mprove understanding of methane and speciated VOC emission s and investigate the use of commercially
available non

- inva sive 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 thie f hatches, 5 pressure relief devices, 3 separators and 1 enclosed combustor control device. A total of 93 emis s ion points were found
with OGI technology at the 23 production sites and the emission rates were measured using a high volume sampler with a subs et of 33 additionally sampled using evacuated canisters

. A28

disproportionate nu mber of detected emissions w ere 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

exce eds the s tate or local emission limits. The study authors concluded c ondensate t ank

- related
emissions observed in the Greeley study were not effectively collected and controlled . H owever , due to single point and instantaneous nature of the measurements, it is not know n if the se uncollect ed emissions exceed the s tate 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 Wo rth 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. Beca use tank

- related emissions vary diurnally and by season and may contain a residual flash emissions component, the extrapolation to yearly values (i.e.
, ton s /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.
, 2014 a ).

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 were29

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 d id 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 id entified 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 b y 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 v ent 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 F acilities W ithin E ach C ategory by L eak R ate

(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).

T he s tudy 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 oil30

and gas production and other sectors. The EP A developed and applied one such mobile inspection technique as part of its Geospatial Measurement of Air Pollution (GMAP) program. (Thoma
, 2012 ; Brantley et al.
, 2014 b ). Designed to be a r apidly

- 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 r epresentative downwind plume sampling, relatively obstruction

- free line of sight observation
, and a knowledge of the distance to the source (Thoma
, 2012 ; Brantley et al.
, 2014 b ).

The EPA used OTM 33A to conduct several survey field campaigns in Weld Coun ty , 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 co nducted 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 execut ed 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.
, 2014 b )

. These data are primarily from well pads a nd 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, a s 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 p reliminary results from the s tudy (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 F ord)

.31

The study authors not e that u sing 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 m any of the high
emission values were attributed to maintenance

- related issues such as open thief hatches
, failed pressure relief valves , or stuck dump valv es

. 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. , 2014 b )

.

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 reduct ion 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 met hane 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 (in cludes 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 emissio ns 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 ope rations.
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 emissi on 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 a n estimated 14 billion cubic feet ( 2 64,000 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 l eak 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 met hane 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 l eaks 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 2011 w as 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 comprehensi ve directed inspection and maintenance (DI&M) program at four gas processing

10 “ Identification and Evaluation of Opportunities to Reduce Met hane 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 proce ssing 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 calculatio n of gas flows into the vent and flare systems. This study did not focus on hy drocarbon 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 u sing 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, un less the leak was above the upper limit of the unit’s design (14 m 3 /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 c omponents (2.6%) were determined to be leaking. The study states that “components in vibrational, high

- use or heat

cycle gas service were the most leak prone.” The majority of the leaks were attributed to a relatively small number of leaking components. Ta ble 2

- 12 presents the breakdown of leak emissions by component type.

Table 2

- 12

. Distribution of N atural G as E missions from L eaking C omponent T ype s

Component Type Percent of Leak Emissions
Valves 30.0%
Connectors 24.4% Compressor Seals a 23.4% Open

- En ded 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 St ations 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. T his work was done as follow up on a study done in 2000, referred to as Clearstone I, in which four gas pr ocessing plants were surveyed. ( Note: one of the gas processing plants surveyed in the Clearstone I study was also surveyed in the Clearstone II

stu dy. ) 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 scree ned.

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 screen ed 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 m 3 /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 t echniques 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 th e 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, refe rred 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 survey s 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 rapi d 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 w ere 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 N atural G as E missions from L eaking C omponent T ypes

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 study36

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 in dicated 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 approache s 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
detect ion 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 a n analyzer, such as a TVA or an OVA. In addition, other monitoring tools such as OGI camera s , soap solution, acoustic leak detection , ambient
monitors and electronic screening device s can be used to monitor process components. A summary of these technologies is presented below.

3.1 .1 Portable An alyzers

Description

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

. Th ese instruments are intended to locate and classify leaks based on the
leak definition of the equipment as specified in a speci fic 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 the37

regulation
, be readable to ±2.5 % of the specified leak definition concentration and be eq uipped
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 emi ssions 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” s creening concentration, which represents the upper limit of the portable analyzers (U

. S

. EPA, 2003 a )

. 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, 2003 a )

. 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, 2003 a )

.
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 ionizat ion 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 p hotoionization detector (PID) use s ultraviolet light (instead of a flame) to ionize organic vapors. As with FIDs, the detector response va ries with the functional group in the organic compounds. P hotoionization38

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,
ald ehydes, 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 gase s. These instruments are usually subject to interference because other gases, such as water vapor and CO 2 , 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)

.

C ombustion 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 c ombustion. 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 a n FID , which measures the concentration of organic vapors over a range of 9 to 10,000 ppm (U

. S

. EPA, 2003 a ) . A TVA combines both a FID and a PID and can measure organic vapors at concentrations exceeding 10,000 ppm. T oxic vapor analyzers and
OVAs measure the co ncentration of methane in the area around a leak (U

. S

. EPA, 2003 a )

.
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 openin g, until a maximum concentration reading is obtained. The maximum concentration is recorded as the leak screening value. Screening with TVAs and OVAs can be a39

slow process, requiring approximately one hour for every 40 components , and the instruments requi re 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) pro vides a cost of $10,800 for a portable monitoring analyzer ( RTI , 2011)

. Additional c osts 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)

De scription

Optical gas imaging (OGI) is a technology that operates much like a consumer video

camcorder 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 ar ray 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 ca n 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 ev aluating 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 t he 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 and40

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 , 2 014). 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 calibrat ion, 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 ro ughly 700 components per day ( ICF Consulting , 2003 ). However, the EPA ’s recent work with OGI systems suggest s 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 survey s 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 V OC 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 i n 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 pape r

. )

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 d ifficult. 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

- Flow TM Sampler.

The OGI system is also sensitive to t he 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 temperat ure 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 effectivene ss 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 I ndustry

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 r equirements, and some companies42

are using the technology voluntarily such as through the Natural Gas STAR program

. Additionally, the GHGRP s ubpart 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 requ ire 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 det ect 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 o f 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 audio

visual

- olfactor y inspections (Wyoming Department of Environmental Quality, Oil and Gas Production Facilities, Chapter 6, Section 2 Permitting Guidance, September 2013).

T he Alberta Energy Regulator requires that a “licensee of a facility must develop and implement a pr ogram to detect and repair leaks.” These programs must “meet or exceed” the
Canadian Association of Petroleum Producer ’ s (CAPP) b est m anagement p ractice (BMP) for
leak e missions m anagement (CAPP, 2011) . The CAPP BMP allows OGI technology for performing the se 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 Ac oustic Leak Detector

Description43

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, 2003 a ). 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 lea k size measured by the intensity of the signal (or how loud the sound is) (U

. S

. EPA, 2003 a ).

Applications

Generally, two types of acoustic leak detection methods are used; high frequency
acoustic leak detection and ultrasound leak detection. High frequenc y acoustic detection is best applied in noisy environments where the leaking components are accessible to a handheld sensor (U

. S

. EPA, 2003 a ). Ultrasound l eak d etection is an acoustic screening method that detects airborne ultrasonic signals in the frequen cy 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, 2003 a ) . Ultrasound detectors can be sensitive to background noise, although most detectors typically provide frequency tuning capabilitie s so that the probe can be tuned to a specific leak in a noisy environment (U

. S

. EPA,
2003 a ).

A URS Corporation /U niversity of Texas at Austin (URS/U T ) study described a “through

valve acoustic leak detection device” or VPAC that was used to measure leaks a t 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 w as 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 research44

documents.

3. 1. 4 A mbient/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 o f 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 emissio ns around a site, such as a well site or gathering station, it cannot necessarily pinpoint the equipment that is the source of those emissions. M obile 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 appr oach to detect and then pinpoint VOC and methane leaks. It is believed that future forms of mobile leak detection45

techniques for the oil and gas sector may include lower cost, work truck

- mounted systems that provide fully autonomous detection capability fo r anom a l o us emissions in support of such a n 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 (GMA P) 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 f

uture, 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 season al 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 facil ity 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 E nergy, 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 detectio n of methane emissions.” Available at: http://www.edf.org/energy/natural

- gas

- policy/methane

- detectors

- challenge46

This decision can be based on several factors, including, the cost of fixing the leak and the size
of the leak. A number o f studies discuss costs and effectiveness of various leak repair options.

3.2.1 Quantifying C ost

- E ffectiveness of S ystematic Leak Detection and Repair Programs
U sing Infrared C ameras (CL, 2013)

This study , discussed previously in Section 2
, provided an ana lysis 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 peri od 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 benefit s of repairing the
leaks at mo st 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 w ell 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 f or each of the scenarios is provided in Table 3

- 1

.

Table 3

- 1. Comparison of T hree H ypothetical R epair S trategies for M ulti

- W ell B atteries a

Category Repair all leaks Repair leaks with a NPV>0 Repair leaks

> 20 Mcf
Potential leak reductions after survey 9 4.5% 92.6% 88.1%

Methane abatement cost ($/ton CO 2 e ) 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 surve y, 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 t he 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 A verage L eak R ate and R epair C osts by C omponents at W ell S ites

Component Leak rate (cfm) Repair Costs

Minimum Average M edian 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 Table s 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 Clea r stone I study , discussed in Section 2, p rovided 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

pay back period ( e.g. , 6 months or 1 year ) are implemented . For those cases, the estimated48

per cent of to tal 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 rep air and benefit of the gas captured.

Table 3

- 3

. Achievable E mission R eduction P ercentages for G iven P ositive P ayback P eriods

Emission Type Reduction Payback Period
< 6 months < 1 year < 2 years < 4 years
Natural Gas 78.8% 92.3% 93.1% 94.9%
Metha ne 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 c ost savings of approximately $1.1 million across the plants in the study ( based on a gas value of $4. 50 per M cf). 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 approxim ately $28 0 , 000 per site (the site

- specific values range between $180, 000 and $33 0 , 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 R epair C osts and M ean R epair L ife for S everal C ommon L eaking C omponents

Component Type Basic Repair Costs Mean Repair Life (years) Low High
Compressor Seals a $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. E PA, 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 facili ty 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 pa rtners have re ported using OGI technology to effectively scan large number s of components in a short span of time. The choice of leak detection equipment typically depends on the number of components to be
scanned. O ptical gas imaging technology is popular at facilities that have thousands of50

components, such as at processing plants. From previous field studies conducted by the EPA and Natural Gas STAR p artners, the EPA has observed that typically 20 % of the top leaking components account for approximately 80 % of the emi ssions 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 reco mmended 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 economi cal 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. T he id entification 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 A verage L eak R ate and R epair C osts by Component at Processing Plants

Component Average Component Leak R ate by Location ( Mcf/yr ) Average Repair Cost Non

Compressor Reciprocating

Compressor Centrifugal

Compressor

C onnections 6.7

- - $25

Flanges 88.2 89.7 115 $150

Pressure Relief Valves 3.9 308

- $150

Other Valve s 25 127 63.4 $130

Compressor Seal a

- 1,440 485 $2,000

Open

- Ended Line (OEL) 43

- - $65

Compressor Blowdown OEL

- 1,417 2,887 $5,000
Note: Adapted fro m 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.pd f

a For the purposes of this paper, compressor seal emissions are not considered leaks.52 Table 3

- 6

. Total A verage L eak R ate and R epair C osts by Component at Compressor Stations

Component Average Component Leak R ate by Location ( Mcf/yr ) Average Repai r 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 Re lief 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.pd f

.

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 simil ar factors that were developed in 2005, prior to the implementation of DI&M BMPs in both the se 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 component s. All surveys were conducted after 2007. The study authors used this data to develop average emission factors for each type of component and then53

compared those factors to the factors developed in 2005. Table 3

- 7 provides a comparison of the
emission fact ors 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 h ave Implemented DI&M BMPs

Sector Component Service a 2014 Emission Factor (kg/ hour) 2005

Emission Factor (kg/hour) Ratio of 2014

to 2005 Emission Factors
Gas Compressor Seal b 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 Compre ssor 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 0.0 12

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 (CAP P, 201 4 )

. 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 consider ed 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 decreas ed. The authors did not use this data to develop national or regional estimates of total leak emissions.



### 4.0 SUMMARY

T he EPA has used the information presented in this paper to inform its understanding of leak emissions and potential techniques that can b e 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 20 1 4 GHG I nventory estimate s there are approximately 3 3 2 , 6 6 2 MT of potential methane leak emission s from gas production
, 3 3 , 6 8 1 MT of potential methane leak emissions from gas processing , and 1 1 4 , 3 4 8 MT of potential methane leak emission s gas transmission

.

 Several studies suggest that the majority of methane and VOC emi ssions 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 stud y found th at 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 be ing used to detect leak s for the oil and natural gas
sect ors . These technologies inc lude 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 porta ble 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 possi ble 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, a n OGI in spection 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, t he 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 o il 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 pot ential 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 applica tions

.
8. Please comment on the prevalence of the use of the different leak detection technologies at oil and gas facilities. Which technolog ies are the most commonly used? Does the type of facility (e.g., well site versus gathering and boosting station) affe ct 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 var y 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

te chnology 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 le aks 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 c orrect 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 detec tion 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?



### 6.0 REFERENCES

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