Attachment N

Leaks

Douglas Jordan

Southwestern Energy
Peer-review of “Report for Oil and Natural Gas Sector Leaks”, April 2014,

U.S. EPA Office of Air Quality Planning and Standards (OAQPS)

By Doug Jordan, Director Corporate Environmental Programs, Southwestern Energy 

(SWN)

I. General Comments: 

The Report for Oil and Natural Gas Sector Leaks report (“White Paper”) is a 

compendium of emissions data and mitigation techniques targeting natural gas leak 

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

storage. The stated purpose of the white paper is to provide a “summary of the EPA’s 

understanding of VOC and methane leak emissions at onshore oil and natural gas 

production, processing and, transmission facilities. This includes available emission 

data, estimates of VOC and methane emissions and available mitigation techniques. 

A. White Paper Content

In presenting the information, EPA has rendered no technical opinion on the 

underlying studies and reports. Rather the information conveyed is a summary of 

studies and reports related to “equipment leaks”. We find the summaries, in general, to 

be an accurate reflection of the data contained in the referenced studies and reports. 

However, we recommend that EPA considers the comments provided by both expert 

and public reviewers and reissue the White Paper incorporating those comments and 

additional information (including EPA technical opinions). Otherwise the current 

White Paper could be construed as the authoritative, expert statements of the 

government on the topic of leaks.

B. Definition and Sources of Leaks

In the White Paper, EPA has defined “leaks” as “...VOC and methane emissions that occur 

at onshore facilities upstream of the natural gas distribution (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, 

compressor seals, connectors, pump diaphragms, flanges, hatches, instruments, meters, open 

ended lines, pressure relief devices, pump seals, valves, and improperly controlled liquids 

storage.” The EPA acknowledges that this definition was derived by reviewing the 

various approaches taken in the available literature.

This is a departure from the traditional fugitive component leaks (e.g. valves, flanges, 

connectors, PRV valves, and pump seals) regulated under NSPS Subpart VV, VVa, and 

KKK (applicable to gas processing for over 30 years). 
The 1996 GRI/EPA report1

“Equipment leaks are typically low-level, unintentional losses of process fluid (gas or 

liquid) from sealed surfaces of above ground process equipment. Equipment 

components that tend to leak include valves, flanges and other connectors, pump seals, 

compressor seals, pressure relief valves, open-ended lines, and sampling connections.”

states the following:

The GRI/EPA report employs various sources to develop average emission factor for 

each of the above basic components that are included within equipment that are 

typically found at a facility. The component emission factor was combined with the 

average number of components comprising the facility to estimate the average facility 

emissions. The GRI/EPA report documents the discrete equipment that includes the 

above components in Table 4-1. For example, in the onshore gas production segment, 

the equipment categories include:

• Wellhead emissions

• Heater emissions

• Separator emissions

• Meters and piping

• Gathering compressors (small)

• Large production (gathering) compressors

• Dehydrators

The GRI/EPA has been used as the basis for estimating the “Normal Fugitives” from 

the natural gas sector in U.S. National GHG Emissions Inventories (NEI)2

In addition, several of the reports referenced in this White Paper (including the 1996 

GRI and the 2014 UT Production Sector Methane Measurement Study) do not include 

these extraneous sources of “leaks” (agitator seals, improperly operating tanks, and 

stuck dump valves) as equipment leaks/leaking equipment. Similarly, the API 

. Comparing 

Table A-137 from the NEI with the Table 4-1 from the 1996 GRI/EPA report, it is clear 

that “Normal Fugitive” that the EPA reports includes a set of discrete components 

within a set of equipment normally found at production sites. It does not include 

sources such as operating tanks and stuck dump valves.

 1 Gas Research Institute (GRI)/U.S. Environmental Protection Agency. 1996c. Research and Development, 

Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. June 1996. (EPA-600/R-96-

0800h). 2 Tables A-137 to A-140, 

ANNEX 3 Methodological Descriptions for Additional 1 Source or Sink Categories, EPA, April 2014
Compendium3 includes within Valves, flanges, connectors, pumps, compressor seal 

leaks, and catadyne Heaters the “Fugitive Source” category. The INGAA Guidelines4

define fugitive emissions as “methane leaks from pipelines and system components 

such as compressor seals, pump seals, valve packings, and flanges and piping 

connectors.” Inclusion of operating tanks and stuck dump valves leads to confusion 

both in terms of understanding the emissions characteristics as well as measurement 

and mitigation technologies. Therefore, we suggest limiting the fugitive category 

components to valves, pump seals, compressor seals, pressure relief valves, connections 

and open ended lines. 

Finally EPA includes “improperly controlled liquids storage”, “pump diaphragms”, 

and “hatches” (i.e. open storage tank thief hatches or stuck dump valves) as additional 

“leak sources”. EPA indicates that improper sizing and or operation of these sources 

results in leaks. Although that may be a valid statement, improperly designed or 

operated equipment resulting in a leak is a different category of emissions than the 

traditional fugitive equipment leak and may warrant different monitoring and 

mitigation (e.g. operational monitoring, engineering solutions and/or changes in 

operational practices/procedures) as opposed to those more applicable to traditional 

fugitive leaks addressed in this White Paper.

It is recommended that the Oil and Natural Gas Sector White Paper should focus on the 

traditional sources of “leaks” (aka fugitive components) in order to avoid confusion 

with a classification that has been captured under federal regulations for over 30 years. 

In addition, the emissions characteristics, monitoring and mitigation techniques for 

traditional fugitive components leaks is different than those for the other “sources” 

included in the broader definition of leaks. EPA should consider developing a White 

Paper for these other sources that may relate more to design and or operational issues 

(such as stuck dump valves, diaphragm seals, tank thief hatches, etc.). Finally EPA 

should address compressor related emissions under the Oil and Natural Gas 

Compressor White Paper.

C. Estimates of Leaks and Cost Recovery

Each of the referenced studies appears to establish an emissions rate for the various 

types of leaking components (e.g. valves, flanges, connectors, pump seals, etc). The 

emissions rate is then applied based on an estimated component count. This yields a 

 3 C OMP E N D I UM O F G R E E N H O U S E G A S EMI S S I O N S ME T H O D O L O G I E S F O 

R T H E O I L A N D N A T U R A L G A S I N D U S T R Y, API, August 2009

4 GREENHOUSE GAS EMISSION ESTIMATION GUIDELINES FOR NATURAL GAS 

TRANSMISSION AND STORAGE VOLUME 1 – GHG EMISSION ESTIMATION 

METHODOLOGIES AND PROCEDURES, September 2005
“potential” emissions rate and not an actual emissions rate. There are flaws with these 

assumptions. First, in each study the emissions factor is based on measurements of 

those components found to be leaking. That includes the “fat-tails” or small number of 

sources which contribute to a significant majority of the overall emissions total. And 

although these “fat-tails” are included in developing the “average emissions rate”, the 

components that were not found to be leaking may not be included. This yields a 

higher “average emissions rate”. The UT study did include those components that were 

measured which reflect zero emissions in the average; however, only the components 

measured were included in the averaging and not the total population of components at 

the location. Second the “average emissions rate” is applied to each component. This 

presumes that every component is leaking at that average rate for the entire estimation 

period (typically reported in tons per year). This combination yields a potential 

emission value and not an actual emissions value and improperly inflates both the

emissions associated with leaks as well as estimated “cost recovery”.

As an example, based on a small “data set” of LDAR surveys at 263 SWN wells, a total 

64 leaking components have been identified (by optical gas imaging). Compared to an 

estimated component count of 80,334 (based on Subpart W factors) this yields a leaking 

component percentage of 0.08%. This clearly reflects that not all components are 

leaking and that for the purposes of assessing environmental impact and cost 

effectiveness (of mitigation), the estimate should be based on real emissions. EPA may 

wish to engage with companies that are conducting voluntary and/or regulatory driven 

LDAR programs with the intent of gaining more information on actual leaking 

component percentages and emissions rates.

Finally, in assessing cost effectiveness, the underlying reports make the assumption that 

each entity (e.g. production, gathering, processing, transmission) financially benefits 

from the gas recovered from implementing a leak detection program That may be an 

incorrect assumption especially for gathering, processing, and transmission that receive 

a “fee for service” as they may not own the gas being released/recovered5

 5 This point is reflected in many studies, including ICF “Economic Analysis of Methane Emission

. 

Furthermore, for those entities that can obtain the benefit of recovered gas, it is 

important to assign the correct value to that recovered gas. The value is not the Henry 

Hub price. Rather, one must first subtract royalties, transportation costs, and the 

distribution to other owners or operators. . Accordingly, for the average producer, 

recovery of gas priced at, for example, $4/mcf at Henry Hub might yield a savings of as 

little as $2.50 or less after taking into account these additional costs to the producer.

Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries (2014”). See Page 4-3 and 4-4. 
D. LDAR Monitoring and Cost

EPA addresses several LDAR monitoring options (including both portable and mobile 

monitoring) in the White Paper. SWN recently implemented a companywide LDAR 

program that applies to our well pads, compressor stations and ancillary equipment at 

those locations. By keeping our program focused on “finding and fixing” leaks by 

using an optical gas imaging camera, conducting an annual survey and minimizing our 

recordkeeping to that necessary for tracking and trending of leaking components, we 

believe we are implementing a program that is cost efficient and within the estimated 

ranges presented in the referenced documents (e.g. $400-$1,200 range referenced by 

Clearstone 2013 report). However, cost for other companies to implement a similar 

program may be very different depending on geographic spacing of facilities (SWN 

facilities are in relatively close proximity reducing travel time), geographic location and 

ease of access to facilities (again SWN facilities are located in geographic locations 

where access is relatively easy), facility design (e.g. single well pads vs. multiple well 

pads) and company resources. In addition, if formal Method 21 monitoring (e.g. not 

using optical gas imaging camera), more frequent surveys (e.g. quarterly), or more 

robust administrative elements (e.g. identifying and tagging components prior to 

surveys, software to maintain records, etc.) and/or quantification measurements (e.g. 

HiFlow) are included, then the program costs expand significantly/prohibitively.

SWN also conducted a field trial of the Picarro system (mobile monitoring) in 2013. The 

Picarro system did prove effective at identifying methane leaks at very low levels, 

provided wind speed and direction were within the parameters necessary for detection. 

However, equipment malfunctions prevented us from fully assessing the viability of the 

Picarro system’s ability to quantify the emissions. In addition, access roads at our 

locations may not allow mobile surveys around the entire facility (so surveys would be 

limited to specific wind direction depending on roads in the area of the facility). And 

the Picarro system, although good at identifying methane emissions, does not identify 

the specific source or point of the methane emissions. Hence, an “operator” would 

need to revisit the site that had a leak indication and conduct an LDAR survey to locate 

the leak (which may require the purchase of an optical gas imaging camera to conduct 

the survey). Finally, at the time of our field trial, the “price” for a single Picarro system 

was prohibitive and well above the $100,000 referenced by EPA. 

In this White Paper, EPA has addressed several of the portable analyzers, mobile 

analyzers and other instruments that may be used to conduct LDAR surveys. However, 

the EPA (and the underlying reports) fails to recognize one of the most basic and 
common survey methods routinely implemented by the oil and gas sector. The missing 

method is the Audio-Visual-Olfactory (AVO) inspection. The AVO inspection can be 

implemented at minimal (almost no cost) as operators conduct these AVO’s inspections 

as a common course of business (however, they may not document each 

inspection/survey). The AVO inspection (survey) can identify not only the traditional 

fugitive leaking components, but can also assist the operator in identifying improperly 

operating equipment such as stuck dump valves and thief tank hatches. 

II. Response to “CHARGE QUESTIONS FOR REVIEWERS” 

1. Did this paper appropriately characterize the different studies and data sources 

that quantify VOC and methane emissions from leaks in the oil and natural gas 

sector?

The Oil and Natural Gas Leaks White Paper summarizes the different studies and data 

sources. However: EPA does not render any technical opinions on the different studies 

and data sources. The studies and data sources rely on a relatively small population of 

measurements which are generically applied across the board and do not take into 

account operational differences that may be present due to individual operator practices 

or geographic variables. The studies also are biased by the “fat tail” phenomena 

whereby a small percentage of leaks contributes to the significant majority of emissions.

The more recent studies also incorporate vented emissions sources into the traditional 

leaking components. As indicated above, EPA should address compressor related 

emissions in the Oil and Natural Gas Compressor White Paper and consider addressing 

improperly designed or operating equipment (e.g. stuck dump valves) in a separate 

White Paper as these sources may require different monitoring and/or measurement 

techniques as well as different mitigation actions. 

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. 

See I.B and I.C above

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? 

No comment 
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. 

No comment 

5. Are there types of wells sites, gathering and boosting stations, processing plants, 

and transmission and storage stations that are more prone to leaks than others? Some 

factors that could affect the potential for leaks are the number and types of 

equipment, the maintenance of that equipment, and the age of the equipment, as 

well as factors that relate to the local geology. Please discuss these factors and others 

that you believe to be important. 

No comment

6. Did this paper capture the full range of technologies available to identify leaks at 

oil and natural gas facilities? 

No comment 

7. Please comment on the pros and cons of the different leak detection technologies. 

Please discuss efficacy, cost and feasibility for various applications.

See I.D above

8. Please comment on the prevalence of the use of the different leak detection 

technologies at oil and gas facilities. Which technologies are the most commonly 

used? Does the type of facility (e.g., well site versus gathering and boosting station) 

affect which leak detection technology is used? 

See Section I.D above

9. Please provide information on current frequencies of revisit of existing voluntary 

leak detection programs in industry and how the costs and emission reductions 

achieved vary with different frequencies of revisit.

As indicated in Section I.D above, SWN has implemented a companywide LDAR 

program. Our LDAR program includes AVO surveys as well as leak detection surveys. 

Our program requires an annual leak detection survey employing an optical gas 

imaging camera, leaks to be repaired as soon as practical but within15 days (unless on 

delay of repair status), and a re-survey to confirm that the leak was repaired. Our 

program does not include a dedicated software program to maintain records and we 

have streamlined the “administrative elements” to focus on the information we believe 

we need to track and trend our leaking components.
Based on the above and our projected 2014 well count (approximately 4660 wells and 

1730 well pads), and amortizing up to 7 optical gas imaging cameras over 5 years, our 

estimated implementation cost for the annual survey is approximately $433,000. 

Increasing the frequency to a) semi-annual would increase costs to approximately 

$617,000, b) quarterly to approximately $1,000,000, and c) monthly to approximately 

$2,400,000. Increasing the frequency of surveys would at some point necessitate the 

purchase of additional FLIR cameras, more robust data maintenance systems, as well as 

additional personnel (along with vehicles etc). However, these cost estimates reflect 

conservatively low estimates and the impact of increasing frequency of the surveys.

Based on our early observations of our company wide program (and a <0.08% leaking 

component rate) and the cost estimates above (using optical gas imaging camera), 

would not support an increased frequency of surveys. However, as we track and trend 

our leaking components, we may identify areas, equipment, or components that may 

require more or less frequent surveys. Flexibility should remain to allow operators to 

conduct surveys commensurate with their leaking component observations and cost 

efficiency.

10. Please comment on the potential for using ambient/mobile monitoring 

technologies in conjunction with OGI technology. This would be a two-phase 

approach where the ambient/mobile monitoring technology is used to detect the 

presence of a leak and the OGI technology is used to identify the leaking component. 

Please discuss efficacy, cost and feasibility.

See Section I.D

11. Please comment on the cost of detecting a leak when compared to the cost to 

repair a leak. Multiple studies described in this paper suggest that detecting leaks is 

far more costly than repairing leaks and, due to generally low costs of repair and the 

subsequent product recovery, it is almost always economical to repair leaks once they 

are found. Please comment on this overall conclusion. 

As indicated in Section I.C, for SWN Production facilities we have observed an 

estimated leaking component percentage of 0.08% (total components) or approximately 

20% of our wells having a leaking component. Approximately 89% of the leaking 

components were repaired upon observation, and 100% of the leaking components 

were repaired within 15-days. The majority of the leaking components were connectors 

that were easily “repairable” and no replacement cost or significant personnel cost. Our 

limited observations would support the overall conclusion that the majority of leaks are 

easy to repair (and hence cost effective).
12. If the conclusion is correct that it is almost always economical to repair leaks once 

they are found, then how important is the quantification of emissions from leaks 

when implementing a program to detect and repair leaks? 

If the emphasis of the LDAR program is to detect and repair leaks, then quantification is 

not important unless you are trying to use a quantified rate as justification to either 

repair or not repair a leak. Quantification (e.g. HiFlow) adds additional expenses in 

terms of equipment and manpower. As an example, SWN’s Midstream group was able 

to conduct an LDAR survey of a simple compressor stations in a couple of hours (e.g 2 

hrs). However, upon implementation of leak quantification (with HiFlow), the total 

survey time has expanded to a full day (8 hours) when leaks are identified.

13. Please comment on the state of innovation in leak detection technologies. Are 

there new technologies under development that are not discussed in this paper? Are 

there significant advancements being made in the technologies that are not described 

in this paper?

SWN is a participant in the Methane Detector Challenge which is sponsored by 

Environmental Defense Fund and managed by Southwest Research Institute. The goal 

of this challenge is to encourage the innovative development and eventual 

implementation of a low cost methane detector that can be located at Production sites 

for the early detection of methane emissions. 

In response to a funding opportunity announcement6 by the DOE/ARPA-E, SWN has 

partnered with IBM and Duke University on two separate proposals that deal with 

development of innovative, cost-effective technologies. We hope to see significant 

advancements in this field in the next few years.

 

6 METHANE OBSERVATION NETWORKS WITH INNOVATIVE TECHNOLOGY TO 

OBTAIN REDUCTIONS (ARPA-E) FUNDING OPPORTUNITY ANNOUNCEMENT 

(Funding Opportunity No. DE-FOA-0001128)