## Attachment N

Leaks

Douglas Jordan

Southwestern EnergyPeer

- 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 stat ed 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 report s 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 natura l 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, conn ectors, 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 appro aches 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 3 0 years).The 1996 GRI/EPA report 1

“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 fa cility 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 emissi ons

**•** 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 St udy) 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 nor mally 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 Prot ection Agency. 1996c. Research and Development, Methane Emissions from the Natural Gas Industry, Volume 8 : Equipment Leaks . June 1996. (EPA

- 600/R

- 96

- 080 0h ).

2 Tables A

- 137 to A

- 140, ANNEX 3 Methodological Descriptions for Additional 1 Source or Sink Categories, EPA, April 2014Compendium 3 includes within Valves, flanges, connectors, pumps, compressor seal leaks, and catadyne Heaters the “Fugitive Source” category. The INGAA Guidelines 4 define fugitive emissions as “methane leaks from pipelines and system components such as compressor seals, pump seals, v alve 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 sugges t 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 result ing 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 o pposed 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 co nfusion 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 ot her “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 com ponents (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. Fi rst, 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 thes e “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 e very 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 associat ed with leaks as well as estimated “cost recovery”.

As an example, based on a small “data set” o f 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 80,33 4 (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/recovered 5

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 pro ducer, 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 an d 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 “fin ding 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 o f leaking components, we believe we are implementing a program that is cost efficient a nd 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 f acilities (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 monit oring) 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 a rea 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 cond uct 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 recogn ize one of the most basic andcommon 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 fro m 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 s ources 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 a bove, 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 diffe rent 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 com ment 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 comment4. 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 equipm ent, 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 tec hnologies 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 optica l 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 u p 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 a t 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 increas ing 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 observa tions 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

pres ence 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 personne l 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 h ow 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 L DAR survey of a simple compressor stations in a couple of hours (e.g 2 hrs) . However, upon impl ementation 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 partici pant 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 de tector that can be located at Production sites for the early detection of methane emissions

. In response to a funding opportunity announcement 6 by the DOE/ARPA

- E, SWN has partnered with IBM and Duke University on two separate proposals that deal with

dev elopment 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)