Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW

Washington, DC 

20005-4070 USA

Telephone: 202-682-8319

Fax: 202-682-8031

Email: ToddM@api.org

www.api.org

June 13, 2014

Mr. Chris Frantz

US EPA 

109 T.W. Alexander Drive

Mail Code: #143-05

Research Triangle Park, NC 27709

Re: EPA VOC/Methane White Paper on Oil and Natural Gas Sector Leaks

Dear Mr. Frantz:

The American Petroleum Institute (API) appreciates the opportunity to provide feedback on EPA’s White 

Papers on Methane and Volatile Organic Compound (VOC) Emissions in the Oil and Natural Gas Sector.

On April 15, 2014, EPA released, for external peer review, white papers that focus on technical issues 

covering emissions and mitigation techniques targeting methane and VOCs from five separate emission 

sources. As noted in the Obama Administration’s Strategy to Reduce Methane Emissions, EPA will use 

the papers, along with the input from the peer reviewers and the public, to determine how to best 

pursue additional reductions from these sources. As described below, API does not believe additional 

methane controls should be required at this time. 

API represents over 590 oil and natural gas companies, leaders of a technology-driven industry that 

supplies most of America’s energy, supports more than 9.8 million jobs and 8 percent of the U.S. 

economy, and, since 2000, has invested nearly $2 trillion in U.S. capital projects to advance all forms of 

energy, including alternatives. Many of our members will be directly impacted by any policy decisions 

that may arise from this effort regardless of whether it informs either regulatory action by the federal 

government or states.

API provided technical feedback and expertise throughout the development of the New Source 

Performance Standard (NSPS) Subpart OOOO rule. Each source addressed by the white papers was 

considered for regulation during the development of the NSPS and EPA, ultimately, chose not to 

regulate them. While our understanding of emissions from oil and gas production continues to evolve,

the fundamental merits of requiring additional regulatory control of these sources is unchanged. As 

such, API continues to believe that no additional regulation of oil and gas production sources is 

necessary prior to the full implementation of the NSPS OOOO rule and a subsequent evaluation of 

emissions.
Page 2

Considering the potential for significant impact on our members that may arise from any policy decision 

stemming from the white papers, API has developed significant technical comments (see attached) to 

address a number of technical inaccuracies about the sources and the conclusions that have been 

drawn. Barring significant revision, API believes that the current white papers are simply insufficient to 

inform sound policy decisions and that simply posting comments on the current version will not result in 

an informed process. As such, API recommends the EPA take the following steps:

 Revise the white papers to correct any fundamental flaws or inaccuracies that were identified in 

response to peer review and stakeholder comment (e.g., improved source descriptions, 

improved understanding of emission quantification, misconceptions about emission mitigation 

options)

 Develop a response to comments document that clearly identify the changes the EPA makes to 

the revised white papers and explains the Agency’s rationale for those changes

 Identify emission studies in progress that will better inform EPA’s understanding of these source 

emissions and await the pending study reports

In recent years, there have been significant swings in the national emission estimates from oil and gas 

production sources, including those covered by the white papers, which indicate a necessity to continue 

collecting data to improve our understanding. Much of this learning will come from improved reporting 

under Subpart W of EPA’s Greenhouse Gas Reporting Program as well as current studies and others 

planned in the coming years, which involve taking direct measurements of the sources. EPA and industry 

would both be well served by allowing these studies to inform policy. 

Again, we appreciate the work by EPA to initiate these white papers and the opportunity to provide 

feedback on this effort. API and its members are dedicated to working with EPA to improve our 

collective understanding of these emissions and providing the technical operator experience that’s 

needed to do so. Recognizing the potential for these white papers to inform not only EPA but other 

government agency policy decisions, we request the opportunity to provide additional feedback to the 

Agency in response to any of our comments in advance. Furthermore, we again offer our experience and 

expertise as EPA moves into the policy evaluation phase of this effort.

Sincerely,

/s/

Matthew Todd

Cc: Peter Tsirigotis, EPA

David Cozzie, EPA

Bruce Moore, EPA
Comments on

Oil and Natural Gas Sector Leaks

by EPA Office of Air Quality Planning and Standards

June 2014

Prepared by

The American Petroleum Institute (API)
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

i

Table of Contents

Executive Summary .............................................................................................................................1

A. Introduction ..........................................................................................................................................3

B. Leak Definition ......................................................................................................................................4

B.1. Fugitive Emissions from Equipment Leaks ...................................................................................5

B.2. Incidental Emissions .....................................................................................................................7

B.3. Preventive Maintenance Program................................................................................................8

C. Leaks Emissions Data and Emissions Estimates....................................................................................9

C.1. General Comments for All Studies...........................................................................................9

C.2. Review of Literature Cited in EPA’s White Paper ..................................................................12

D. Leak Prevention and Detection...........................................................................................................26

D.1. Techniques Reviewed in the White Paper.............................................................................27

D.1.1. Portable Analyzers (Reference Method 21) ..........................................................................27

D.1.2. Optical Gas Imaging (OGI)......................................................................................................28

D.1.3. Acoustic Leak Detector..........................................................................................................29

D.1.4. Ambient /Mobile Monitoring ................................................................................................29

D.2. Additional Techniques EPA Should Consider.........................................................................30

D.2.1. Auditory, Visual, and Olfactory (AVO) Method for Leak Detection.......................................30

D.2.2. Leak Prevention – Preventive Maintenance Program...........................................................30

E. Repair: Cost and Cost-Effectiveness ...................................................................................................31

E.1. Cost Considerations...............................................................................................................31

E.2. Cost-Effectiveness Analyses in Previous Studies...................................................................34

E.2.1. EPA White Paper 3.2.1 - Quantifying Cost-Effectiveness of Systematic Leak Detection and 

Repair Programs Using Infrared Cameras (Carbon Limits, 2013).......................................................35

E.2.2. EPA White Paper 3.2.2 - Identification and Evaluation of Opportunities to Reduce Methane 

Losses at Four Gas Processing Plants (Clearstone, 2002)...................................................................36

E.2.3. EPA White Paper 3.2.2 – Cost-Effective Directed Inspection and Maintenance Control 

Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well 

Sites (Clearstone, 2006)......................................................................................................................37
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

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E.2.4. EPA White Paper 3.2.4 - Natural Gas STAR Directed Inspection and Maintenance (EPA 

2003a, EPA 2003b, and EPA 2003c)....................................................................................................38

E.2.5. EPA White Paper 3.2.5 - Update of Fugitive Equipment Leak Emission Factors (CAPP, 2014)

...............................................................................................................................................39

E.2.6. NSPS Subpart OOOO Technical Support Document (TSD) (U.S. EPA, 2011 and 2012)..........40

F. Summary .............................................................................................................................................41

G. Conclusions and Recommendations...................................................................................................42

H. Charge Questions................................................................................................................................44

References ..................................................................................................................................................48
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

1

Executive Summary

The U.S. Environmental Protection Agency (EPA) has developed a draft document titled Oil and Natural

Gas Sector Leaks (hereinafter “the White Paper”) to, as stated in the Preface, seek input and solidify its 

understanding of the methane and volatile organic compounds (VOCs) emissions from leaks in this 

industry sector. The American Petroleum Institute (API) hereby submits its input and comments in this 

document.

In the White Paper, EPA defines leaks as VOC and methane emissions not only from equipment 

components (e.g., valves, flanges, connectors) that are traditionally covered in the Leak Detection and 

Repair (LDAR) programs under its New Source Performance Standards (NSPS) and National Emissions 

Standards for Hazardous Air Pollutants (NESHAP) regulations, but also from unintended incidents where, 

for example, storage tank thief hatches are left open or separator dump valves are stuck open. 

Emissions resulting from such incidents have not been well documented or characterized, but may emit

at higher emission rates than emissions from equipment component leaks. Most of the unintended 

incidental emissions are caused by equipment failure, dirty process fluids, lack of maintenance, or 

operator error. Typically, these unintended incidental emissions can be easily identified through 

operator’s routine checks on process equipment using sensory inspection methods in a timely manner. 

A traditional LDAR program is not efficient in identifying such incidental emissions due to the 

randomness of their occurrence and because Method 21 is designed to detect on-going leaks from 

cracks or mated/sealed connections; however, incidental emissions often occur at thief hatches, 

intermittent vents, or sumps. As shown in the Picard, et al., 2006 study, even for fugitive equipment 

leaks, Method 21 is not efficient in finding leakers with high emission rates. However, a modern optical 

gas imaging (OGI) IR camera would be efficient in detecting fugitive equipment leaks with high leak 

emission rate.

Two of the most relevant general conclusions for leaks at oil and gas production sites reached by the 

various emissions studies cited by EPA are: 

(1) Predominantly high percentage of total facility leak emissions are attributed to very few highly 

leaking components; and

(2) Leaks at production sites are typically low in volume and frequency, challenging the conclusion 

that an LDAR-type ‘find-and-fix’ program is always cost effective. 

For instance, according to a Canadian report (CAPP, 2007), for a leak definition of 10,000 ppm, only the 

top 5 to 10% of leaking components account for 80 to 90% of total fugitive emissions from upstream oil 

and gas facilities. Additionally, a recent study (UT, 2013) suggests that one third of production sites had 

no detectable leaks and that, of the 66% sites that had any detectable leaks, the average total emissions

(both leaks and vents) per site was 0.23 standard cubic feet per minute (scf/min). This is only 330 scf per 

day (scfd) per well site. At $5.40 per thousand cubic feet (Mcf), this is a natural gas loss of $1.79 per day. 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

2

Another recent study (Carbon Limits, 2014) suggests an average leak emissions rate per site of 0.4

scf/min (leaks only, not vents). This is 576 scfd per well site and lost natural gas value of $3.11 per day 

per well site. 

Based on the very low methane losses per well site (UT, 2013; Carbon Limits, 2014), it is clear that only a 

very low-cost and integrated approach to addressing both the fugitive emissions from equipment leaks 

and the incidental emissions should be considered by EPA for any future cost-effectiveness analyses. 

One such approach is a preventative maintenance program which allows the use of sensory inspections.

It can reduce the occurrence of both types of leaks more effectively than a reactive “leak detection and 

repair” program. 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

3

A. Introduction

The American Petroleum Association (API) appreciates the opportunity to present this set of comments 

on EPA’s draft Oil and Natural Gas Sector Leaks, Report for Oil and Natural Gas Sector Leaks Review 

Panel (U.S. EPA 2014, subsequently referred to in this document as “the EPA White Paper”, or “the 

White Paper”). 

The scope of EPA’s White Paper appears to include volatile organic compound (VOC) and methane leak 

emissions from oil and natural gas production, natural gas gathering and boosting, processing, 

transmission and storage operations (i.e., upstream of the city gate). However, API’s comments 

presented herein focus on primarily oil and natural gas production, gas gathering and booster stations, 

and, to a lesser degree, gas processing plants. The organization of this set of comments generally 

follows that of the White Paper, except that additional sections were inserted where appropriate and 

necessary to cover topics not specifically addressed in the White Paper.

EPA noted in their Introduction section that, “The emissions data and the mitigation techniques in this 

paper are based on the onshore natural gas leak emission...”. Therefore, the focus of this White Paper is 

onshore natural gas facilities with some data pertaining to oil production also presented. Offshore 

operations are not covered. 

In the White Paper, EPA used the term “co-producing” to describe oil wells producing significant 

quantities of both oil and gas. This is a recently introduced and inaccurate term infrequently used in the

industry. We do not support the use of this imprecise term as it is not consistent with the historical 

designations used by states, the federal government, and industry for over a century.

EPA noted in the White Paper that, based on the EIA projection1natural gas development in the U.S. is 

expected to increase by 44% from 2011 through 2040 along with an approximately 25% increase in 

crude oil and natural gas liquids through 2019. The projected growth is primarily led by the increased 

development of shale gas, tight gas, and coal-bed methane resources using new production technology 

and techniques such as horizontal drilling and hydraulic fracturing. 

According to the EPA, the amount of relevant equipment – with the potential to leak – will increase with 

the number of wells being drilled and in operation. What EPA failed to recognize is that the amount of 

relevant equipment is not expected to grow at a pace similar to the increase of overall production due 

to the existence of currently underused capacity and capacity that would become available due to 

declining production of existing producing wells. 

 

1

U.S. EIA, 2013b
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

4

B. Leak Definition

In the White Paper, EPA defines leaks as VOC and methane emissions that occur at onshore facilities 

upstream of the natural gas distribution system (i.e., upstream of the city gate), including 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. 

According to EPA potential sources of leak emissions from these sites include:

 Agitator seals, 

 Compressors seals, 

 Connectors,

 Pump diaphragms,

 Flanges, 

 Hatches, 

 Instruments and meters, 

 Open-ended lines, 

 Pressure relief devices, 

 Pump seals, 

 Valves, 

 Improperly controlled liquids storage, and

 Equipment that is not operating correctly, such as storage vessel thief hatches that are left 

open, or separator dump valves that are stuck open.

In this definition, as well as throughout EPA’s White Paper, the authors attempt to broaden the scope 

and lump together fugitive equipment leak emissions and unintended incidental emissions resulting 

from equipment failures, upsets, and operator error. In contrast, the mitigation techniques discussed in 

Section 3 of the White Paper focus solely on detection of fugitive emissions from equipment leaks. 

Additionally, the emissions discussed in Section 2 of the White Paper are predominantly fugitive

emissions from equipment leaks, but some unintended incidental emissions sources, as described 

below, are also included in these emission estimates. These incidental emissions are not well 

documented and are difficult to quantify. Some qualitative discussions have theorized that incidental

emissions are larger than fugitive equipment leaks, while other discussions lead to the belief that 

fugitive equipment leaks are greater than incidental emissions because of the potential temporary and 

short duration nature of incidental emissions. 

We believe that it is important to define leaks for the purpose of this White Paper as including: 1) 

fugitive equipment leaks, and 2) unintended incidental emissions. However, it is also important to 

understand that the traditional methods for detecting fugitive emissions from equipment leaks are not 

effective for identifying incidental leaks because of where the emissions occur (Method 21 detects leaks 

from cracks or mated/sealed connections while incidental emissions often occur at thief hatches, vents,

sumps, etc.). While equipment leaks may typically continue until repaired, incidental emissions may be

more of a temporary nature since they are often found during regular site visits by operating personnel.
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

5

As shown in the Picard, et al., 2006 study, even for fugitive equipment leaks, Method 21 is not efficient 

in finding leakers with high emission rates. However, a modern optical gas imaging (OGI) IR camera 

would be efficient in detecting both the incidental emissions and fugitive equipment leaks with high leak 

emission rates.

The following sections discuss in further detail fugitive emissions from equipment leaks, incidental

emissions, and a preventive maintenance program that could help minimize both types of leaks.

B.1. Fugitive Emissions from Equipment Leaks

We believe that a working definition of “fugitive equipment leak” can be articulated as follows 

(modeled on the definition used in CAPP, 2007):

A fugitive equipment leak is defined as a loss of process fluid to the environment past a seal, 

threaded or mechanical connection, cover, valve seat, flaw or minor damage point on 

equipment components in hydrocarbon service, which results in a detected concentration (or 

mass emission rate) that is above a given threshold. 

Consistent with the above definition, emissions of VOC and methane from the following sources 

would be considered fugitive emissions from equipment leaks:

 Equipment components traditionally included in the LDAR program as prescribed in the 

NSPS and NESHAP regulations (except for venting from compressor seals which are covered 

in a separate white paper), such as valves, connectors, pump seals, sampling connections, 

pressure relief devices, and open-ended lines. Leaks from such components are typically 

caused by the failure of seal, gasket, packing, O-ring, etc. due to normal wear, improper 

installation, improper maintenance, insufficient lubrication, or other reasons.

 Excessive emissions from the thief hatch seal (i.e., emissions greater than the maximum seal 

leak rate specified by the manufacturer) on an oil, condensate, or produced water storage 

tank, if the tank is connected to a control device via a closed vent system. However, thief 

hatches and pressure relief devices have an inherent leak rate. No thief hatch or pressure 

relief device is 100% leak free since is it not welded closed. The manufacturer specifies the 

leak rate depending on the gaskets or seals that are used. This inherent leak rate would be 

considered normal operation and would not fit the definition of ‘leak’, since it is both 

intended by design and required for proper operations.

The emissions and emission sources that should not be considered leaks include emissions of VOC 

and methane from:

 All cases where a piece of equipment is operating properly and as designed, such as:

o Pneumatic devices;
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

6

o Thief hatches and vents on oil, condensate, or produced water storage tanks when 

open as designed (e.g., thief hatch during sampling or gauging operations, vents to 

atmosphere on tanks that are not tied to a control device via a closed vent system);

o Enardo and pressure relief devices when opening at the pre-set pressure as 

designed (including weighted thief hatches designed for pressure relief) to prevent 

equipment explosion or implosion;

o Truck vents during loading; and

o Vents or exhaust stacks on process equipment, such as heaters, engines, glycol 

dehydrators, amine units, sulfur recovery unit tail gas thermal oxidizers, etc.

Even though, in general, EPA seems to agree with this approach in the White Paper2, several

studies and reports reviewed and cited by EPA in the White Paper do include process 

equipment vents in their definition of a leak, for example, the City of Fort Worth Natural Gas 

Air Quality Study (ERG, 2011), the Greenly, CO study (Modrak, 2012); Carbon Limits’ study 

(Carbon Limits, 2013); and Mobile Measurements studies in CO, TX and WY (Thoma, 2012). . 

 "Improperly controlled liquids storage" which is defined as a leak in Section 1 of the EPA 

White Paper in a footnote as, "Emissions beyond the required level of control from control 

equipment that is not operating properly, such as leaking vapor recovery units, or 

improperly sized combustors...". Improperly controlled liquids storage tanks would be a 

violation of the control requirements in specific provisions of the state or federal regulations

(e.g., NSPS, NESHAP) and/or permit conditions. It should not be defined as a leak, since it 

may result in duplicative regulatory requirements that may conflict or cause multiple leak 

detection strategies or recordkeeping. Of all studies and reports reviewed and cited in the 

White Paper, tank emissions are included as part of leaks in at least the following: the Fort 

Worth study (ERG, 2011); the Greely, CO study (Modrak, 2012); and the Mobile 

Measurement studies in CO, TX and WY (Thoma, 2012). It is not clear whether storage tanks 

included in these studies were “properly controlled” or not at the time of emission 

measurements.

 Compressor seals. Traditionally, compressor seals are included in EPA's LDAR regulations for 

the chemical and refining industry. However, in EPA's current effort in addressing VOC and 

methane emissions from the oil and gas industry, a separate technical white paper is being 

developed for compressors. Additionally, in EPA's latest regulation on the oil and gas 

industry, namely, NSPS Subpart OOOO, compressors are not included in the LDAR 

provisions. Rather, they are addressed in separate sections which require emission controls, 

and/or maintenance practices that are different from the traditional LDAR program. 

Therefore, emissions from compressor seals should not be included as part of leaks. When 

presenting compressor seals data throughout this White Paper, EPA did make an effort to 

 

2

See page 3 of the White Pater: “(f)or the purpose of this paper, emissions from equipment intended to vent as 

part of normal operation, such as gas driven pneumatic controllers, are not considered leaks.”
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

7

note that “for the purpose of this paper, compressor seal emissions are not considered 

leaks.”

B.2. Incidental Emissions 

We believe that a working definition of incidental emissions is:

Incidental emissions are emissions in excess of equipment design or normal operating 

procedure that may be caused by equipment failure, dirty process fluids, lack of 

maintenance, or operator error. 

Examples of incidental emissions include stuck separator dump valves, open tank thief hatches, or 

hydrocarbons drained to a water sump or tank containment. As discussed earlier, incidental

emissions are different in nature from the “fugitive emissions from process equipment leaks” that 

are historically covered under the LDAR programs required in NSPS and NESHAP regulations. The 

differences between the two are as follows:

 Incidental emissions are emissions resulting from exceeding equipment design and/or 

deviating from normal operating procedures. They may occur due to lack of maintenance, 

exceeding operating parameters, failure of process equipment, not following operating 

procedures, or operator error; while the leak emissions covered under the traditional LDAR 

program typically result from normal wear or improper fitting of connection points (e.g., 

flanges), or seals and gaskets on moving parts of valves, pumps, etc.

 While many emission studies have been performed on fugitive equipment leaks, incidental

emissions are not well documented or quantified. Incidental emission rates are typically 

much higher than emission rates from fugitive equipment leaks, but may be of shorter 

duration than fugitive equipment leaks since they are often identified during site visits by 

operators.

 Because of the high emissions and impacts to operating equipment, incidental emissions are 

often found during routine operation checks which typically use sensory inspection methods. 

Sensory inspections (namely, auditory, visual and olfactory (or AVO) inspections) have long 

been considered the backbone of any good inspection program. They are reliable methods 

for identifying the most obvious and significant emissions release events. In addition to 

incidental emission events, fugitive equipment leaks with higher emission rates can also be 

found during sensory inspections. However, a traditional LDAR program is not efficient in 

identifying incidental emissions because monitoring survey intervals are typically quarterly or 

less frequent. Furthermore, Method 21 is designed to detect leaks from cracks or 

mated/sealed connections while incidental emissions often occur at thief hatches, vents, or 

sumps. As shown in the Picard, et al., 2006 study, even for fugitive equipment leaks, Method 

21 is not efficient in finding leakers with high emission rates. However, a modern optical gas 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

8

imaging (OGI) IR camera would be efficient in detecting both the incidental emissions and 

fugitive equipment leaks with high leak emission rate.

Because incidental emissions can sometimes result in relatively high emissions, some state 

regulatory agencies have begun to address this issue. An effective mitigation measure is to develop 

and implement a properly designed preventive maintenance and training program, which would

help reduce the number of occurrences of incidental emissions at a facility and shorten the total 

time of an incidental emission. In fact, such a maintenance and training program would also help 

reduce the fugitive equipment leaks as defined in NSPS and NESHAP regulations as well. 

B.3. Preventive Maintenance Program 

To address both the fugitive emissions from equipment leaks and incidental emissions, EPA should 

consider cost-effective integrated approaches. In the development of such approaches, the EPA 

should consult the monitoring studies on oil and gas facilities conducted by the Texas Commission 

on Environmental Quality (TCEQ) over the last several years prior to finalizing their permit-by-rule

under 30 TAC 106.359 which authorizes emissions from planned maintenance, startup, and

shutdown (MSS) activities. The TCEQ found that the larger leaks are from poorly maintained sites. 

“Based on the analysis of modelling data and correlated monitoring and sampling data, the 

required use of Best Management Practices (BMPs) will result in reduced short-term and longterm emissions from oil and gas sites (OGSs). Monitoring data indicates that emissions at levels 

of concern predominately result from sites that are not properly maintained or that do not 

follow BMPs. Authorized emissions from planned MSS activities are short-term and result in 

reduced overall emissions and environmental impact. Permit holders are required to develop 

and implement a maintenance program, and comply with the recordkeeping requirements in 

§106.8 (Recordkeeping) and the site-wide emission limits in §106.4 (Requirements for 

Permitting by Rule).”3

Preventive maintenance programs would be far more effective at addressing emissions from leaks in 

the oil and gas sector than an inflexible, one-size-fits-all LDAR program. Adherence to a properly 

designed preventive maintenance program would minimize equipment failures and leak emissions

proactively. In contrast, an LDAR program is a reactive measure (waiting for leaks to occur and 

finding them). 

In general a maintenance program may consist of a variety of activities that are applicable to 

operating location, type of operations and equipment used. An operator should be allowed to have 

the flexibility to design the preventive maintenance program such that it is most suitable for the 

site. For example under the TCEQ permit by rule for oil & gas operations maintenance, startup and 

 

3

38 Texas38Texas Register 52755271, August 16, 2013
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

9

shutdown activities4, each company is allowed to develop their own maintenance program 

according to what is most suitable for maintaining their sites. The operator should be able to select 

the type and level of site inspection based on factors such as the leak emissions, the materials 

handled at the site, and the cost-effectiveness of the inspection. Typically, the use of AVO 

inspections are most effective in detecting the most obvious and significant emissions release 

events, resulting in the most cost-effective reduction of high volume emission leaks. Generally, it is 

affordable for the vast number of small operators in oil and gas industry who only operate very few 

sites each. On the other hand, operators who own and operate many sites in a certain area may 

find it more desirable to use, in addition to AVO inspections, other technology, e.g., optical gas 

imaging (OGI) IR camera. 

Unnecessarily burdensome and inflexible recordkeeping and/or reporting requirements would make 

any maintenance program much less cost effective than it could be. If a leak is identified and 

repaired immediately before the inspection/maintenance crew leaves the site prior to the end of 

the work day, no records should be required. Only records that are necessary for the company to 

generate a repair or maintenance work order should be kept.

In summary, API recommends that if EPA moves forward with regulation for leaks, EPA should adopt 

an integrated approach to prevent or minimize leak emissions. For the oil and gas production 

sector, including gas gathering and booster stations, a preventive maintenance and training program 

could be used to proactively address both fugitive emissions from equipment leaks and incidental

emissions. 

C. Leaks Emissions Data and Emissions Estimates

A total of twelve studies/reports were reviewed and summarized in Section 2 of the White Paper, 

representing EPA’s current understanding of the leaks emissions data and emission estimates for the oil 

and natural gas sector. Another report discussed in Section 3.2.5 (CAPP, 2014) was an update of fugitive 

equipment leak emission factors. In addition, API believes EPA should consider results from another 

study (Picard, et al., 2006) which was conducted as a companion to Clearstone II. API’s comments on 

those fourteen studies/reports and on EPA’s review of them are presented in this section. However, 

comments in this section primarily focus on emissions data and emissions estimates in those studies.

API’s comments concerning repair costs and economic analyses in those studies are discussed in Section 

E.2. 

C.1. General Comments for All Studies

Two of the most relevant general conclusions for leaks at oil and gas production sites reached by the 

various emissions studies cited by EPA appear to be: (1) predominantly high percentage of total 

 

4

http://www.tceq.texas.gov/permitting/air/permitbyrule/subchapter-o/mss-oil-gas.html. See the PDF for Section 

106.359, under (c) Best Management Practice.
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

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facility leak emissions are due to very few highly leaking components, and (2) leaks at production 

sites are typically low in volume and frequency, challenging the conclusion that an LDAR-type ‘findand-fix’ program is always cost effective. For instance, according to a Canadian report (CAPP, 2007),

for a leak definition of 10,000 ppm, only the top 5 to 10% of leaking components account for 80 to 

90% of total fugitive emissions from upstream oil and gas facilities. Additionally, a recent study (UT, 

2013) suggests that one third of production sites had no detectable leaks and that, of the 66% sites 

that had any detectable leaks, the average total emissions (both leaks and vents) per site (with an 

average of 2.3 wells) was 0.23 scf/minute. This is only 330 scfd per well site. At $5.40 per Mcf5, this 

is a natural gas loss of $1.79 per day. Another recent study (Carbon Limits, 2014) suggests an 

average leak emissions rate per site of 0.4 scf/min (leaks only, no vents). This is 576 scfd/well site 

and lost natural gas value of $3.11 per day per site.

Other general conclusions reached by a review of the studies and reports discussed in the White 

Paper are as follows:

 The VOC and methane emissions from leaks, as defined by EPA in this White Paper 

(including both traditional fugitive emissions and incidental emissions), have not been 

reliably quantified, estimated, or documented either at a facility level, or at a regional or 

national level. 

 “Leak” emissions data and emission estimates historically only include fugitive emissions 

from equipment and do not include incidental emissions. For example, the 1995 Protocol 

(EPA, 1995), the GRI/EPA Study (GRI/EPA, 1996), the GHG RP (EPA, 2013), and the GHG 

Inventory (EPA, 2014). While the uncertainty in emission estimates for incidental emissions 

is substantial, even considering only fugitive equipment leaks, accurate emission estimates 

do not exist because elements such as emission factors and representative component 

counts are outdated and not representative of the broad range of oil and gas production 

facilities currently in operation.

 Accurate emission estimates are crucial to reasonable cost-effectiveness analyses for 

mitigation options. As the first step, EPA should focus on improving estimates of leaks 

emissions, including both fugitive equipment leaks and incidental emissions. For example, 

the fugitive equipment emissions can be improved by obtaining accurate component counts 

at well sites, tank batteries, and compressor stations, as well as emission factors that apply 

to those facilities.

Most, if not all the studies reviewed (see detailed comments below), were designed to estimate 

total facilities emissions and they were undertaken primarily within a geographical region and for a 

limited number of facilities. Therefore, the data presented may not necessarily be representative of 

 

5

This price, $5.40 per Mcf, is the average Henry Hub natural gas spot price ($/Mcf, assuming 1020 BTU/scf) from 

January 2001 to April 2014. However, the net revenue that the well operator receives is far less than this amount 

due to costs such as royalty payment, transportation cost, etc. 
API Comments on Submitted to EPA

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11

overall leakage rates or emission factors per component. For developing representative emission 

factors one has to take into account both the leak definition and the percentage of components that 

are expected to leak over that threshold for each component type. To complete the analysis, there 

is also a need for a representative count for each type of component in different facility categories 

in order to estimate total potential emissions and their mitigation potential.

The studies discussed below, where field measurements were conducted to support the emissions 

estimates, data was collected using a variety of sampling and measurement techniques, instruments 

and protocols, along with an inconsistent set of other assumptions. As a consequence the data 

obtained may not all be comparable and could also impact data quality and increase the uncertainty 

of the conclusions reached - such as cost-effectiveness of emissions mitigation.

For example, although the use of optical gas imaging (OGI) where the IR camera is outfitted with a 

methane band-pass filter that allows clear identification of methane plumes, its detection threshold 

may vary. Operator skill, rigor of calibration, facility location, and ambient conditions may affect the 

sensitivity of the camera and the minimum quantifiable emissions that can be determined. 

Additionally, such optical imaging devices may capture gas plume images that do not emanate from 

what is traditionally considered “equipment leaks” but may originate from pneumatic devices, 

process equipment, hatches and other vented releases that are associated with either normal 

operations or other potential equipment failures. 

At the same time, instruments that are based on flame ionization detectors (FID) or Thermal 

Conductivity (TC) detectors (e.g., TVA or HiFlow samplers) have the ability to detect a wide range of 

hydrocarbons and their mixtures and are best at measuring total organic compounds (TOC).

Therefore, they would require a compositional profile for the detected gas or vapor in order to 

characterize emissions of specific fractions such as methane, other individual hydrocarbons and 

total VOCs. 

Even with all the methodological differences, it is still clear that from the preponderance of the 

evidence from all the studies, predominantly high percentage of total facility leak emissions are due 

to very few highly leaking components. The studies indicate that natural gas processing plants tend 

to have more fugitive equipment leaks than compression or transmission of natural gas, with the 

lowest emissions from equipment leaks being attributed to well pad operations. 

For the studies cited, which use the emissions data as a baseline scenario to assess the cost 

effectiveness of mitigation strategies, two essential features are apparent:

(i) The costs of identifying fugitive equipment leaks vary considerably for geographically 

dispersed facilities with low densities of components, such as production operations at the 

well pads (detailed comments on cost issues are presented in Section E) ; and

(ii) The estimation of expected - or projected – future years emissions should not be correlated 

directly to the increase in production or processing capacities, and should be justified 

separately before assuming an emissions growth factor. 
API Comments on Submitted to EPA

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12

API encourages EPA to pay special attention to the uncertainty of the derived emission estimates 

and the data quality issues described above. To reiterate, accurate emission estimates are crucial to 

a reasonable cost-effectiveness analysis for mitigation options and the derivation of realistic 

marginal abatement costs.

Further comments on each of the studies and documents cited by EPA follow below.

C.2. Review of Literature Cited in EPA’s White Paper

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

The EPA protocol provides standard procedures for estimating the total organic compound mass 

emissions from leaks at oil and natural gas production facilities. The data used was provided by 

multiple studies with extensive participation by the oil and natural gas industry via API. The data 

provided were for the following equipment types: valves, pumps, compressors, pressure relief 

valves, connectors, flanges, and open-ended lines. Industry also participated in the data analysis 

that resulted in four recommended emission estimation methods: (a) average emission factor 

approach; (b) screening ranges approach; (c) EPA correlation approach; and (d) unit specific 

correlation approach.

API’s Comments

(1) The EPA correlation approach is suited for use at facilities that perform periodic screening of 

components such as natural gas processing plants that are subject to NSPS or NESHAP regulations.

(2) Both the average emission factors and the screening range approaches provided are outdated 

and could benefit from updating with more recent data.

(3) The 1995 protocol does not address the use of optical imaging devices such as IR cameras. EPA 

should review available comparative data6and update the protocol to facilitate the use of such 

devices.

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

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

The study relied on EPA Method 21 screening of target components (up to the upper range of 

100,000 ppm with a dilution probe) and the use of a HiFlow sampling device and correlation 

equations for determining mass emissions. One of the features of the study was that the facilities 

were divided into categories of eastern and western natural gas production to account for regional 

differences in the methane content of the natural gas. The study estimated that for the 1992 base 

 

6 M, Lev-On et. al., “Derivation of New Emission Factors for Quantification of Mass Emissions When Using Optical 

Gas Imaging for Detecting Leaks”, Journal of A&WMA, September 2007
API Comments on Submitted to EPA

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13

year overall methane emissions from all the natural gas sector in the U.S. amounted to 314 + 104 (+

33%) billion standard cubic feet (Bscf), or about 1.4+ 0.5% of natural gas production. Out of this,

methane emissions from onshore production were estimated to be 16.23 (+ 45%) Bscf, and the 

contribution from gas well emissions was about 13.8%.

API’s Comments

(1) The approach used was very thorough and provided representative emission factors for the 1992 

base year, but the factors should be updated to better reflect equipment leaks emissions today. 

(2) There is a need to look at regional differences in natural gas composition because the 

demarcation of Eastern and Western natural gas does not seem to be relevant any longer.

(3) The global assumption that average emission rates should be adjusted to methane emissions by 

assuming a content of 78.8 vol % (69.6 wt %) for all U.S. Natural Gas production is not 

representative of the variability of natural gas compositions.

(4) The component counts per location are based on a limited number of sites (1-17) for each region 

which is hardly representative. To improve component counts, far more sites would need to be 

visited and their components counted per equipment type.

EPA White Paper 2.3 - Greenhouse Gas Reporting Program (GHGRP) (U.S. EPA, 2013)

The GHGRP specifies different methods for calculating emissions from leaks for the different 

industry segments. For onshore petroleum and natural gas production, reporters use population 

counts and population emission factors for calculating emissions from leaks using the appropriate 

population emission factors specified in the subpart W regulations. For gas processing and gas 

transmission facilities, reporters use counts of leaking components (> 10,000 ppm) and screening 

range emission factors for calculating emissions from leaks. The counts of leaking components are 

obtained by an annual leak survey. 

According to the GHGRP data disclosed by EPA for the 2011 and 2012 reporting year, methane 

emissions from equipment leaks were 396,099 and 364,453 metric tonnes, respectively, 

representing 17.4% and 16.0% of total reported methane emissions from onshore production for 

the two respective years. 

API’s Comments

(1) The emission factors specified for use in the GHGRP for the onshore petroleum and natural gas 

production are based on decades’ old (mid-1990s) emission factors (see EPA White Paper 2.2 above) 

for major pieces of equipment. 

(2) These factors are no longer representative of current industry operations and ought to be 

updated to better reflect actual emissions from equipment leaks.

(3) Similarly, Appendix G of the Technical Support Document for reporting under Subpart W of the 

GHGRP presents the population emission factors to be used for emission estimation. However, no 

reference is provided for the basis of the equipment counts by component type that would be the 

basis for such average emission factors. The only general reference provided is to the same decades 
API Comments on Submitted to EPA

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14

old data source (GRI/USEPA, 1996). These counts are based on a limited number of sites and need to 

be reviewed and updated.

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

2014)

The U.S. GHG Inventory which is prepared annually by EPA includes estimates of methane and 

carbon dioxide emissions for natural gas systems and petroleum systems, including onshore 

production and other industry segments. EPA has subdivided its estimation of emissions into six 

regions that are compatible with EIA’s National Energy Modeling System (NEMS) regions, as used for 

forecasts and energy outlooks. These regions are: North East, Midcontinent, Rocky Mountain, South 

West, West Coast, and Gulf Coast. Distinct emission factors are used for estimating emissions – for 

each of the regions - from gas wells, separation equipment, gathering compressors, gathering 

pipelines, drilling and well completions, normal operations, condensate tank vents, well workovers, 

liquids unloading, vessel blowdowns, and process upsets.

EPA uses the 1996 GRI/EPA study as the basis for the emission factors with adjustments that reflect 

more recent data on regional gas compositions (2001 GTI study). For natural gas processing and gas 

transmission, emission factors are not broken into regions, and national level emission estimates are 

provided. Potential methane leak emissions from gas wells and field separation equipment for 

onshore natural gas production were estimated to be 332,662 MT for the 2012 inventory. The 

emission estimates provided in the national inventory are first expressed in terms of potential 

emissions and then reduced to “net” emissions based on a list of emission reductions estimated by 

EPA due to state and federal regulatory actions and voluntary reductions by industry.

API’s Comments

(1) The National GHG Inventory emissions estimates for Natural Gas Systems (production through 

distribution) and Petroleum Systems (production through refining) are not directly comparable to 

the data reported under the GHGRP; since – for example - Petroleum Refining emissions are 

incorporated with Petroleum Systems in the national inventory.

(2) Moreover, API has also commented previously that due to increased focus on emissions from 

associated gas, the national inventory should clearly identify the emissions from associated gas that 

are included in the Petroleum Systems. In the 2013 emission inventory report (addressing the year 

2011 emissions) these emissions were listed under “Tank Venting” in Section 3.6 of the main 

inventory report and under “Oil Tanks” in Section 3.6 of Annex A. For improved clarity and 

transparency, API suggested including “associated gas emissions” in parentheses where emissions 

from these sources are presented. It also suggested to EPA that for future inventories, Petroleum 

Systems should include an emission source category for “associated gas venting and flaring” 

emissions to align with the GHGRP.

(3) EPA acknowledges that it continues to use the 1996 GRI/EPA emission factors for many sources 

although it emphasizes that these emissions are potential emissions factors representing what 
API Comments on Submitted to EPA

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15

emissions would be if practices and technologies had not changed over time. However, it does not 

cite directly what are the expected net emissions from these equipment leaks sources.

(4) In its comments to EPA on the year 2011 inventory API reiterated its previous comments to 

suggest that a table (or tables) be added to the methodology annex (typically Annex A) to document 

the methane composition data that are used for both the Natural Gas Systems and Petroleum 

Systems. 

(5) In its comments on EPA 2014 national inventory report (addressing the year 2012 emissions) API 

supported EPA’s action to continue to disaggregate emission source information and applicable

emission reductions, to provide better transparency of “net” GHG emissions for each source type. 

The approach historically used by EPA of lumping together reduction activities for multiple inventory

sources made it difficult to attribute these reductions to specific inventory source categories.

EPA White Paper 2.5 - Measurements of Methane Emissions at Natural Gas Production Sites in the 

United States (Allen et al., 2013, or UT, 2013)

This study is often referred to as the University of Texas (UT) 2013 study. The measurement of 

equipment leaks reported in this publication is part of a more comprehensive study of emissions 

from natural gas production operations. For this characterization, equipment leaks data was 

collected from 278 well sites in four different regions of the continental U.S., where initial scanning 

was performed with IR camera (detection threshold 30 gr/hr – 0.026 scf/m) to identify potential 

leak sources. All identified leaks were measured with a HiFlow Sampler. Data includes equipment 

leaks information from wellhead equipment, piping, flanges, fittings, valves, and separators; but 

does not include flashing from tanks or engine exhausts.

Table S2-4 in the paper’s appendix provides information on emissions from equipment leaks per 

well site as summarized in the table below.

API’s Comments

(1) Most noteworthy is that one-third of the well sites had no detectable leaks. For the 66% of the 

wells surveyed had any detectable leaks, the leak rate per well was low. The highest measured leak 

rate of 0.10 scf/min/well is only 144 scfd/well. At a natural gas value of $5.40 per Mcf, this is 

Table C-1: Emissions Per Well (all leaks detected with FLIR Camera)

Appalachian Gulf Coast Mid-continent Rocky Mountains Total

Sites visited

(sites with leaks 

detected)

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

Methane Emission 

Rates (scf/min/well)

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

Whole Gas Emissions 

Rates (scf/min/well)

0.100 + 0.060 0.058 + 0.033 0.055 + 0.034 0.047 + 0.034 0.070 + 0.024
API Comments on Submitted to EPA

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approximately 78 cents per day per well of lost natural gas. The study also found that, among the 

sites visited, there are 2.3 wells per site in average. Therefore, the value of natural gas loss at each 

site is approximately $1.79 per day. This suggests that any proposed leak mitigation technology 

must have a very low burden to be cost effective and should target the large leaks and incidental 

emissions.

(2) The focus of the study was not on equipment leaks and these measurements were performed in 

an ad hoc fashion with no a priori design for representativeness of data collected and results.

(3) The methodology used in the study does carefully account for methane emissions by 

characterization of gas composition at every site and subtraction of non-methane species 

concentrations from Total Organic Carbon measured by FID.

(4) Detailed measurement data by component is needed for further use of this data to derive 

updated emission factors or to estimate cost-effectiveness of emission mitigation.

EPA White Paper 2.6 - Fort Worth Natural Gas Air Quality Study (ERG, 2011)

The goal of this study was to assess the air quality impacts of oil and gas facilities in the Ft. Worth 

area. The facilities surveyed included: 375 well-pads, 8 compressor stations, and one (1) each 

processing facility, saltwater treatment facility, drilling operation, fracking operation, and 

completion operation (flowback).

The sampling strategy was to survey sites by IR camera to identify all larger leaks which were 

measured with HiFlow samplers. Concurrently, a survey of 10% of all components was conducted 

with a TVA to obtain an estimate of the presence of smaller leaks. Canisters (total of 164) were 

collected from some of the high leakers for speciation of constituents. 

API’s Comments

(1) The focus of this study was air quality and health impacts of exploration and production 

operations within the City or Fort Worth. Measurement of equipment leak emissions was only a 

small portion of this study. Considering these factors as well as the limited geographic scope of the 

study, it is questionable that the results from this study would be very useful for the purpose of the 

Leaks White Paper.

(2) Emissions were calculated only for detected leaking sources which could be measured.

(3) The emission factors cited by this study are skewed toward high level emissions for a small 

fraction of the components since not all of the emissions were calculated and/or characterized for 

all sources. 

(4) The study identified that for well pads and compressor stations the most frequent emissions 

were observed from pneumatic valve controllers and the highest emission rates were detected with 

the IR camera from leaking tank thief hatches. 

(5) The rationale for using a multiplier of 7 to assess the number of valve connectors and a factor of 

10-15 for compressors connectors is not clear and not justified in the study documentation. Based 

on component counts conducted in previous studies, such as from EPA/GRI 1996 data, a factor of 3-

5 is more appropriate for onshore production operations.
API Comments on Submitted to EPA

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(6) At 96 of the 375 sites tested no emissions were detected by the IR camera; most of these sites 

contained three wells or less.

EPA White Paper 2.7 - Measurements of Well Pad Emissions in Greeley, CO (Modrak, 2012)

The primary purpose of this study was to determine the accuracy of the Bacharach Hi Flow Sampler 

(BHFS) in measuring streams with high VOC contents. The study determined that the BHFS 

volumetric emission rates are biased low when compared to canister-determined emission rates for 

sampled combustible concentrations exceeding 10%. 

The paper presents a graph of methane and VOC mass emission rates determined using the BHFS 

total flow rate and gas speciation data collected by canister for “tank” and “non-tank” sources. The 

tank emissions include breathing and flashing losses, where the flashing loss measurements are 

based on manually induced flashing events. Non-tanks emissions include all other auxiliary 

equipment at the well pad site. The paper does not provide component or equipment specific 

results for the non-tank measurements.

API’s Comments

(1) The data reported in the White Paper (page 28) do not reflect the information provided in the 

cited extended abstract. The abstract notes that a more detailed report on the study is in 

preparation. It appears EPA had access to preliminary information from the report.

(2) The study states that measurements should not be extrapolated to yearly values, which the 

White Paper acknowledges and states should not be used for comparison to permit or control limits. 

However, the White Paper does report annual emissions values “for informational purposes”.

EPA White Paper 2.8 - Quantifying Cost-Effectiveness of Systematic Leak Detection and Repair 

Programs Using Infrared Cameras (Carbon Limits, 2013)

Carbon Limits issued a draft report in December 2013 and published a final report in April 2014. 

There are no significant differences between the two. Comments related to the emissions data in 

this Carbon Limits report are presented in this section; additional comments related to the cost data 

are discussed in Section E.2.1.

The report states that there is considerable variability in leak rates across the data available for the 

facilities surveyed. The data used for the analysis indicated that gas processing plants leak the most; 

well sites and well batteries have lower leaks, with about one third having no reported leaks and 

only 7% having leaks above 500 thousand standard cubic feet (Mcf) per year. Based on the evidence 

in this report, compressor stations leak more than well sites and well batteries, but less than gas 

plants.

The data used for the economic analysis was obtained from service providers that conduct 

inspections at oil and gas sites and it included 58,421 components, which were either leaking or 

venting gas. The analysis in the report focuses primarily on leaks from static components, 
API Comments on Submitted to EPA

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comprising 39,505 of the individual emission sources in the database. The data identified that 44% 

of gas plant emissions were attributed to leaks, with 36% of compressor stations emissions and 17% 

of well-sites and well batteries also contributed by leaks. 

The report references the ICF work to state that 30% of methane emissions from onshore natural 

gas production emissions are from leaks but this lumps together traditional equipment leaks and 

vents. Carbon Limits claims that, based on their database, 35% were due to leaks, but they too are 

lumping together both venting and leaking including pneumatic controllers and thief hatches, for 

example. Since the database consists primarily of Canadian facilities that have been subject to a 

directed inspection and maintenance program for some time, the authors state that the distribution 

of emissions may not be representative of distributions of similar emissions in the US, where 

systematic leak detection and repair programs are less common. 

Table C-2: Comparison of the Carbon Limits Study with Previously Published Work (in cfm)

API’s Comments

(1) The study found that vents are the most common source of gas emissions from the identified 

emission sources. However, as EPA noted in the White Paper, vented emissions are not considered 

 

7

Includes: Pressure relief valves, regulators, block valves, connectors (unions, flanges, and plugs), and control 

valves.

8

Includes: Crank case vent, compressor seals, open-ended lines, orifice meter, glycol dehydrators, pneumatic 

controllers, equipment blowdowns and purging activities, tank vents, combustion equipment.

9

For well sites and compressor stations, glycol dehydrators, pneumatic controllers, equipment blowdowns and 

purging activities, tank vents, flares, and combustion equipment are not included.

10 Estimate per well site based on the average number of wells per wellsite.

Wellsite & well

batteries

Compressor

stations

# of

assessments

Results

(cfm)

# of

assessments

Results

(cfm)

Carbon Limits 

Data Surveys Used

Average leak 1,764 0.4 1,915 1.4

Average vent 1.2 2.4

Average emissions 2.1 3.8

Fort Worth 

Natural Gas air 

quality study

Average leak 375 NA 7 6.4

Average vent NA 4.3

Average emissions 3.1 10.7

Clearstone 2006 Average leak712 NA 7 NA

Average vent8NA NA

Average emissions90.8 12.2

University of 

Texas 2013

Average emissions 146 0.2310 NA NA
API Comments on Submitted to EPA

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leaks for the purpose of this White Paper. From the comparison table above, the average leak rate

(excluding vents) at wellsites and well batteries was found in this study to be 0.4 scf/minute. This is 

only 576 scfd/well site. At $5.40 per Mcf, this is a natural gas loss of $3.11 per day. At such a low 

value for gas loss, it is not likely that a more vigorous analysis would show any instrument-based 

monitoring and recordkeeping program would be cost effective.

(2) In the table above, it is not clear whether the “compressor stations” category includes the 

booster stations in production fields only, or both booster stations and the compressor stations

used for interstate natural gas transmission. In general, transmission stations are expected to have 

higher emissions due to both the higher operating pressures and the size of compressors used at 

those facilities. Assuming the “compressor stations” category in the table only includes production 

field booster stations, the CL study suggests average leak emissions per site of 1.4 scf/min. This is 

2016 scfd/station and lost natural gas value of $10.88 per day per site. 

(3) The authors erroneously state that emissions from US facilities are expected to be higher than 

typical emissions from Canadian operations. They quote a value of 17% emissions from leaks for well 

sites and well-pad batteries from their data base, which is very consistent with the GHGRP 2011 and 

2012 data in which methane leaks account for 17.4% and 16.0%, respectively, as compared to 

onshore production emissions. 

(4) The selection of facilities and the quality of the data generated by the two private companies 

who participated in the study are questionable. As potential benefactors from any regulation that 

would mandate the services they provide, concerns over conflict of interest are heightened.

Selection of the facilities provided for the study is not discussed in the paper and the statement, 

“The data were made available ... and checked for quality/consistency...”, is not supported by any 

description of the criteria used for determining quality assurance or consistency.

(5) While general information about facility types is given (well sites, batteries, compressor stations, 

gas plants), no specific information on locations (i.e., facility density, remoteness of location, type of 

production, climatic conditions) is documented. In fact, the footnote to Table 2 giving the number 

of each type of facility surveyed states that,

“Information based on discussion with the data providers. However, this information is not 

documented in the database. As a result, it is generally not possible to quantify the distribution 

of facility sizes or sub-categories within the three categories of facility type, not to analyze how 

leak rates or net program cost vary between subcategories.” 

All of these factors will significantly impact the overall cost of a program, so the ‘cost-effectiveness’ 

conclusions are anecdotal, at best.

(6) The approach taken by Carbon Limits is that once leaks are detected and measured, or 

estimated, repairs can be conducted economically, reducing emissions by 90% or more. The authors 

do not provide any explanation for these assertions nor do they indicate whether the assumed 90% 

reduction would be uniform for all baseline emission levels and for all components, and whether all 

of these repairs could be conducted immediately on site or would require a separate trip to the site 

to complete, or even a well shut-in or a plant shut-down. 

(7) The emissions used to justify the conclusion that it is economic to fix a leak once it is found, are 

based on some measured emissions and some estimated emissions. The ratio of measured vs. 
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estimated emissions was not quantified, so it is highly uncertain whether the economic conclusion 

can be justified.

(8) The authors make a sweeping assumption that over 90% of the emissions are from leaks that 

can be repaired with a payback period of less than one year. They do not address any barriers, such 

as inaccessible components, safety considerations, or the necessity of shutting in equipment or a 

facility, which would prevent immediate repair. The authors do contradict themselves when they 

acknowledge that the net present value (NPV) of an LDAR program is highly dependent on the 

number of identified emission sources, their leak rates and the ultimate effort that is required to 

perform the repairs.

(9) It is important to note that the database used by the authors also lumps in 255 instances of 

improper venting from damaged pneumatic controllers and open thief hatches, which the authors 

claim are inexpensive and simple to repair. The inclusion of these highly emitting release events is 

inappropriate since these are not fugitive equipment leaks; their emissions will artificially inflate the 

baseline emissions making it seem that it is cost-effective to control them. These vents should be 

removed from the database that is used in the analysis of cost-effectiveness of an LDAR program. 

(10) The global warming potential (GWP) used by Carbon Limits for deriving CO2-equivalent (CO2e) 

emissions is set at 25 for methane. Although this is identical to EPA’s revised GWP for reporting 

from 2013 and beyond, it is not comparable with available data. The latest national GHG Inventory 

(2012) and GHGRP disclosed data (2012), as well as the other previous studies cited by EPA, use a 

GWP of 21 for methane. Therefore the mere application of the new GWP factors will increase 

estimated GHG emissions by 19%. Moreover, the authors proceed to offer a brief sensitivity analysis 

for higher GWPs from the IPCC 5

th Assessment Report (AR5). This is confusing at best and should be 

overlooked especially since there is no formal action for adoption of the even newer GWP factors.

(11) It should be recognized that part of the differences between the emissions from the studies 

could be due to the variability in the monitoring and quantification methodology, i.e. TOC, VOC or 

methane, along with the different GWP that is cited for deriving CO2e emissions. 

(12) The authors state that the VOC and CO2e emissions are merely based on “the qualitative 

description of the type of gas emitted from each source, a gas composition was assumed for each 

leak in the database and a CO2e and a VOC emission factor have been calculated (see Appendix 3).” 

They did not use actual measured compositions or obtain actual stream compositions.

EPA White Paper 2.9 - Mobile Measurement Studies in Colorado, Texas, and Wyoming (Thoma, 2012)

The study presents the results of testing a mobile measurement technique from 5 field studies. 

Each measurement from the mobile unit captures a 20-minute “snap shot” of emissions at distances 

ranging from 20 to 200 m from the well pad. All measurements were conducted during daylight 

hours on days without significant rainfall. Measurement locations were selected based on locating 

emissions through a down-wind drive-by inspection. The mobile unit was then positioned “at an 

appropriate and safe location near the highest observed CH4 concentrations”. The report presents 

aggregated emission results by state, which are reflected in the White Paper.

API’s Comments
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(1) The report states that with “strict application and favorable conditions”, the point sensor-based 

remote measurement is “believed capable of measurement accuracies in the ± 30% range”.

(2) The measurement approach specifically targets the highest emission locations observed for the 

well sites that were in the drive-by area and only captures emissions over a short duration. This 

method cannot be used to extrapolate the measurements to an annual inventory.

(3) This approach captures any emissions upwind of the measurement vehicle, and therefore cannot 

be used to assess emissions from individual source types.

EPA White Paper 2.10 - Economic Analysis of Methane Emission Reduction Opportunities in the U.S. 

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

The analysis is based on the 2011 U.S. GHG Emissions Inventory as published by EPA in April 2013 

with revisions that include updated information from the GHGRP and the University of Texas,

Austin, measurements campaign. This revised 2011 baseline was used for projecting onshore 

methane emissions to 2018. This study devised a separate category for gathering and boosting 

operations rather than the current GHG Inventory practice of including it in the onshore production 

segment. The study also determined that there are 909 gas processing and treatment facilities in the 

U.S. The ICF study adopted the narrow definition of Fugitive Emissions to mean “methane that leaks 

unintentionally from equipment such as flanges, valves and other equipment”.

API’s Comments

(1) The ICF study assumes that 2011 methane leaks from wells amounted to 283,000 metric tonnes

(using the higher Emission Factor above); 56,600 metric tonnes from processing; and 3,800 metric 

tonnes from pipeline leaks from transmission of natural gas, for a sum total 343,400 metric tonnes 

of methane.

(2) For comparison, the methane emissions from equipment leaks were reported as 397,935 metric 

tonnes from the GHGRP [98.236(c)(15)], and 377,880 MT from the national GHG Inventory.

(3) It is not clear how the ICF study ended up with a total estimate of national emissions from leaks 

in the natural gas production, processing, transmission and storage segments for 2011 to be 604,000 

metric tonnes of methane.

(4) The working assumption of the ICF study is that methane emissions from the oil and gas sector 

will increase by 4.5% from the 2011 baseline to 2018, regardless of the implementation of new 

regulations. This is not consistent with information that they provided in briefings in which they 

have indicated that for the period 2011 to 2018 net methane emissions from natural gas systems is 

expected to decrease by 1% while net methane emissions from petroleum systems is expected to 

increase by 26%, primarily from venting and flaring of associated gas, and flaring of associated gas is 

expected to result primarily in increased CO2 emissions and not CH4 emissions.

(6) ICF does not provide any discussion of the impact of production decline and the plug and 

abandonment of wells with lower production of wells.
API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13, 2014

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EPA White Paper 2.11 - Identification and Evaluation of Opportunities to Reduce Methane Losses at 

Four Gas Processing Plants (Clearstone, 2002)

This study (Clearstone I) involved the assessment of voluntary Directed Inspection and Maintenance 

(D&IM) program at four gas processing plants in the Western U.S. The survey included 101,193 

individual equipment components. 

The study estimated that 94.9% of the total natural gas losses due to leakage at the inspected 

facilities are cost-effective to reduce. Such action may result in 75.9% of emissions reduction for 

methane. The study concludes that implementing all equipment repair or replacement 

opportunities will reduce natural gas losses from fugitive emissions by 95%. 

The authors recommend devising Best Management Practices to assist companies in developing loss 

control programs.

API’s Comments

(1) The focus of this study is natural gas processing plants some of which are already subject to LDAR 

programs and therefore some of the findings about potential for equipment leaks emission 

reduction may have already been attained by regulatory requirements. 

(2) Total GHG emissions from source in the four facilities surveyed are due to fuel combustion of 

compressors and process heaters (79.6%), equipment leaks (15.7%), acid gas removal (2.6%), and 

flare/vent systems (1.8%).

(3) Of the methane emitted 82% was due to equipment leaks, with incomplete combustions and 

flares accounting for 10.1% and1.6%, respectively.

(4) About 2.6% (2,630 out of 101,193) of components in natural gas service were determined to be 

leaking (i.e. had a screening value > 10,000 ppm)

(5) Components in vibrational, high-use, or heat-cycle gas service were the most prone to leaks. 

(6) The majority of the emissions from fugitive equipment leaks are attributable to a small number 

of leaking components: valves contributed 30% of the total, connectors 24.4%, compressor seals 

23.4%, open-ended-lines 11.1%, crankcase vents 4.2%, pressure relief devices 3.5%, with other 

equipment accounting for the remaining 3.4%.

(6) Fixing the 10 highest emitting cost-effective-to-repair components at each site (refer to Appendix 

II for a ranked listing emission rates by payout period) would reduce natural gas losses by 

approximately 481.8 mscfd or 35.2 percent.

EPA White Paper 2.12 - Cost-Effective Directed Inspection and Maintenance Control Opportunities at 

Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites (Clearstone, 

2006)

This study (Clearstone II) was a follow-up to the study shown in 2.11 above and it surveyed 74,438 

components and approximately 2.2% were found to be leaking (> 10,000ppm). The study provides 

component counts and leak frequencies for each of the five gas plants studied.
API Comments on Submitted to EPA

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23

API’s Comments

(1) A targeted DI&M program aimed at proven opportunities can significantly reduce the time and 

resources required to identify and repair those leaks that represent the “low hanging fruit” within 

the facility. Components associated with vibration (i.e. compressors) and heat-cycle (i.e. mole sieve) 

services contributed 97% of the total fugitive equipment leaks. These results again emphasize that 

employing a targeted DI&M program would significantly reduce the cost of initiating a DI&M 

program.

(2) Fugitive equipment leaks accounted for 55% of all natural gas losses from the facilities studied.

(3) For Equipment Leaks sources: OELs accounted for 32% of total natural gas losses, followed by

connectors (30%), compressor seals (20%), and block valves (15%). The remaining 3% were from 

pressure relief valves, regulators, orifice meters, control valves, and crank case vents.

(4) Comparison of emission factors in terms of Total Hydrocarbon (THC) is provided below. Note: the 

EPA/GRI 1996 study quantified methane so those factors are expected to be smaller than those for 

THC.

Table C-3: Comparison of Average THC Emission Factors (Kg/hr/source)

Source Phase I 

Study 

(Clearstone 

2002)

Phase II 

Study

(Clearstone 

2006)

U.S. EPA

(1995 

Protocol)

EPA/GRI Study

(Methane; 1996)

Connectors 0.00222 0.00330 0.00020 0.000305

Block Valves 0.0110 0.0147 0.00045 0.0034

Control Valves 0.0485 0.0373 0.00045 N/A

Pressure Relief Valves 0.0673 0.000470 0.00880 0.00224

Pressure regulator 0.0174 0.00631 0.00880 N/A

Orifice Meter 0.00358 0.00270 0.00880 N/A

Crank case vent 0.883 0.120 N/A N/A

Open Ended Line 0.0518 0.239 0.0020 0.0902

Compressor Seals 0.852 0.520 0.00880 1.17

(5) Although 7 compressor stations and 12 wells were surveyed, the 5 gas processing plants 

surveyed made up over 93% of the components monitored. The compressor stations and well 

surveyed were located near and upstream of the gas processing plants, thus they do not represent 

the broad differences in production facilities due to the geographic breadth, variety of facilities, 

differences in the characteristics of products handled, and operating practices of the companies. 

Conclusions from this study should only be applied to gas processing plants.

(6) Clearstone (2006) references a separate study that integrated a passive midwave infrared 

camera survey at the same time the Clearstone (2006) study was performed. That study is 

documented in “Directed Inspection and Maintenance Survey at a Gas Fractionation Plant Using 

Traditional Methods and Optical Gas Imaging” (06-A-119-AWMA) and discussed further below. The 
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Clearstone (2006) study did state that the IR camera is capable of screening leaks approximately 3 

times faster than conventional methods (for two people: typically 2,400 components/day for 

conventional versus 6,400 components/day for the optical)

(7) The authors recommended that a best practices document be developed to disseminate and 

encourage the compilation and use of cost-effective emissions reduction practices. The document 

should also provide information required by companies to develop site-specific programs for 

reducing their methane and non-methane hydrocarbon losses, and greenhouse gas emissions (e.g., 

delineate source categories and/or facility areas to focus efforts on for maximum benefit, generic 

cost data for evaluating control options, recommended monitoring frequencies, and typical repairs 

life expectance by source type and service category).

An Additional Study Not Included in EPA White Paper – “Directed Inspection and Maintenance Leak

Survey at a Gas Fractionation Plant Using Traditional Methods and Optical Gas Imaging” (06-A-119-

AWMA) (Picard, et al., 2006)

As a companion study to Clearstone II, a separate study was conducted at a gas fractionation plant, 

which was also included in Clearstone II. EPA should also consider results from this study. The purpose 

of this work was to 1) quantify methane, total hydrocarbon (THC) and greenhouse gas (GHG) emissions

and 2) identify and evaluate potential cost-effective emissions reducing opportunities. A tertiary 

objective of the survey was to qualitatively compare the performance of optical gas imaging with 

traditional leak detection methods (Method 21).

The measurement program comprised a fugitive emissions survey of all equipment components in 

natural gas, NGL, ethane, propane, butane, iso-butane, normal butane, and condensate service. A total 

of approximately 77,800 individual equipment components were surveyed for leaks using a combination 

of traditional screening techniques and the optical gas imaging camera.

The study reaches the following conclusions:

(1) The majority of losses from fugitive equipment leaks are attributed to a relatively small number 

of equipment components. Only 423 (or 0.5 percent) of the components surveyed were determined 

to be leaking, and of these, 320 were determined to be cost-effective to repair. Implementing all 

cost-effective repairs would reduce hydrocarbon emissions by an estimated 465,000 m

3

/y and GHG 

emissions by 826.5 tonnes CO2e per year. The 320 economically repairable leaking components 

resulted in an estimated 470,800 m

3

/y of natural gas. 

(2) The study shows that both detection methods tested failed to identify some of the leaking 

components. Based on the ten largest emission points shown in Table 5 of the comparison study, 

five were detected by traditional Method 21 screening methods and eight were found by optical gas 

imaging. The five leaking components not detected by Method 21 could have been due to flame out 

of the sensor due to the large leak rate. The two leaking components that were not detected by the 

optical gas imaging camera were large enough, and above the camera sensitivity threshold, but 

were missed by the camera operator. 
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(3) In contrast to the percentages of emissions accountable to each component reported in 

Clearstone II, (see (2) under EPA White Paper 2.12 above), this Optical Imaging Study of the same 

facilities found the relative distribution of total hydrocarbon emissions attributable to each 

component type (on a volumetric basis) to be as follows: OELs 25%, connectors 14.7%, compressor 

seals 0%, valves 37.7%, control valves 9.1%, crank case vents 2.4%, pump seals 10.1%, PRVs 1%.

API’s Comments 

(1) The passive mid-infrared camera used in this study was an early prototype. Modern optical 

cameras would have been more likely to identify all of these leaks. However, the Method 21 

screening methods did not find 5 of the largest 10 leakers in this study.

(2) The ten largest leaking points resulted in 226,300 m

3

/y or 48% of the total leak emissions. The 

five leaks that were not detected by Method 21 emitted only 62,300 m

3

/y or 27.5% of the top ten 

leakers.

EPA White Paper 3.2.5 – Update of Fugitive Equipment Leak Emission Factors (CAPP, 2014)

This report presents updated average emission factors for estimating emissions from fugitive 

equipment leaks at upstream oil and natural gas facilities in Canada, commissioned by the Canadian 

Association of Petroleum Producers (CAPP). In 2007 CAPP published a best management practice 

(BMP) for Management of Fugitive Emissions at Upstream Oil and Gas Facilities and provincial 

regulations came into effect to better manage these emissions. The CAPP Fugitive Emissions BMP 

provides guidance on implementing directed inspection and maintenance (DI&M) procedures to 

specifically target fugitive equipment leaks. 

The updated factors provided in this 2014 report are reflective of current conditions at facilities that 

have implemented DI&M programs in accordance with the BMP and applicable regulatory 

requirements. The report summarizes leak survey results for 120 facilities in Alberta (82) and British 

Columbia (38), where typical (default) component counts were applied to each type of process or 

major equipment unit, resulting in an estimate of 276,947 components for the facilities reported.

Two methods were used for mass emission determinations: 

 Method 1 - application of post-2007 leak frequency data and CAPP (1992) Leak and No-Leak 

emission factors. This method was only applied where leak-rate measurement results were 

unavailable.

 Method 2 - application of post-2007 leak detection and measurement results for leaking 

components and estimation of emissions contributions from non-leaking components using 

the CAPP (1992) no-leak emission factors. An equipment component is generally deemed to 

be leaking if it produces a screening value of 10,000 ppm or greater when screened in 

accordance with U.S. EPA Method 21, or the emissions are detectable by a leak imaging 

infrared camera.
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26

Table 10 from the final report presents a consolidated view of emission factors before and after the 

implementation of CAPP’s Best Management Practices for a DI&M program.

API’s Comments

(1) The survey uses a somewhat ambiguous definition for “leaking” component in Method 2. It could 

be either screens > 10,000 ppm in accordance with U.S. EPA Method 21, or emissions are detectable 

by a leak imaging infrared camera.

(2) A comparison of the current survey with the one conducted in 2005 indicates that, overall, the 

emissions due to fugitive equipment leaks have decreased by 75% since the implementation of 

DI&M programs. 

(3) Emission factors for connectors in gas/vapor service at natural gas facilities were unchanged, 

while emission factors for all other categories with more than 50 leakers showed substantial 

reductions compared the CAPP (2005) values. 

(4) These results suggest that DI&M programs and CAPP’s best management practice for 

Management of Fugitive Emissions at Upstream Oil and Gas Facilities are effective in controlling 

fugitive equipment leaks. 

(5) The study notes that for the data collected since 2007, only one of the companies provided 

component counts by component type. For the others, detailed component counts were based on 

default equipment schedules applied to the number and types of process equipment units as 

determined from process flow diagrams (PFDs) and piping and instrumentation drawings (P&IDs), 

meter schematics, and equipment inventory files creating some uncertainty in the data. 

(6) The percentage of leaking components in Table 5 is highly uncertain because the component 

counts by type were estimated as discussed in Section 3.1.

(7) Five of the facilities provided leak data without emission measurements and the leak rate was 

estimated as discussed in Section 3.2. The remaining facilities submitted actual emissions 

measurements and these facilities showed significant decreases in emissions as discussed in Section 

3.3.

(8) The emissions factors for control valves and regulators showed increases compared to the 2005 

factors which CAPP believes “may reflect the impact of better leak measurement data for these 

sources, but is suspected to be largely due to poor quality of the component counts for these 

categories potentially resulting in an overstatement of the leak frequencies.” 

D. Leak Prevention and Detection

In Section 3 of EPA’s White Paper, Available Emissions Mitigation Techniques, there are two subsections: 3.1 (Leak Detection) and 3.2 (Repair). Section 3.1 discusses four leak detection techniques, 

while Section 3.2 merely presents a summary of five studies/reports/documents that had information 

about cost-effectiveness analysis or payback period estimates for repairing leaks detected.

In this document, API presents in Section D its comments on EPA’s Leak Detection discussion, and in 

Section E comments on EPA’s Repair section. 
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D.1. Techniques Reviewed in the White Paper

Under Section 3.1 on Leak Detection, EPA included portable analyzers, optical gas imaging, acoustic 

leak detectors, and ambient/mobile monitoring – all reactive measures (find the leak after it 

happens). EPA did not include auditory, visual, olfactory (AVO) monitoring or proper maintenance 

and repair programs. EPA seems to assume that for the proper detection of leaks, a technology is 

required to determine if a leak exists, ignoring that human senses (eyes, ears, and smell) can detect 

most significant leaks at a facility. EPA also overlooked the idea that a proper maintenance and 

repair program could be implemented to minimize the frequency of leaks, especially the larger 

leaks, which reflects a more proactive approach. “Mitigation Techniques” as suggested by the title 

of EPA’s Section 3.0 should include techniques not only for detecting leaks, but also for helping 

prevent leaks. The complete omission of these two ideas from the White Paper is extremely 

concerning. EPA should evaluate the AVO method for detecting leaks in comparison to the use of 

the four techniques described in the White Paper. EPA should also consider and evaluate a proper 

maintenance and repair program to help prevent leaks instead of requiring an overly burdensome 

leak detection and repair program that will not prevent any leaks (both the fugitive equipment leaks 

and the incidental leaks) from occurring.

For two of the four techniques discussed in the White Paper, portable analyzers and ambient/ 

mobile monitoring, EPA included nominal cost information about purchasing the instrument. 

However, the true cost for implementing a leak detection program using one of those techniques is 

far beyond the instrument cost. See Section E.1 for a detailed discussion on cost. 

D.1.1. Portable Analyzers (Reference Method 21)

In Section 3.1.1, EPA claims that organic vapor analyzers measure the concentration of methane. 

This is incorrect. Organic vapor analyzers measure concentrations of hydrocarbons based on an 

ionization response of emitted hydrocarbons mixture. Concentrations are derived through 

instrument calibration and the application of response factors and are not typically component 

specific although the instrument response varies with the number of carbons in the 

hydrocarbon chain (it is possible to use an FID analyzer equipped with a gas chromatograph, but 

these devices are expensive, impractical to use in the field, and not required to comply with 

Method 21). 

More cost data is needed from vendors on the portable analyzers, calibration and maintenance, 

and training in use of the analyzers. For example, capital recovery costs have not been 

appropriately quantified. Some typical Method 21-compliant devices and costs include:

 Rae Systems PPBRAE 3000 - $7060.00

 Thermo Scientific TVA-1000b - $8500 - $12,000, depending on features (FID only, 

FID/PID dual). Datalogger / manager - $8400 (current typical rental day rates = 

$110/day or $350/week)
API Comments on Submitted to EPA

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28

Operating costs, such as calibrations, maintenance, and operator training and certifications have 

not been rigorously quantified and incorporated into the cost-effectiveness analyses. 

D.1.2. Optical Gas Imaging (OGI)

Infrared (IR) cameras using OGI technology can be an important tool in voluntary ‘find and fix’ 

programs for reducing leak emissions and EPA rightly points out there are limitations to the 

cameras. The White Paper states, “The EPA is currently studying OGI technology in order to 

determine its capabilities and limitations”. That being the case, mandating the use of OGI 

technology prior to understanding those capabilities and limitations is unwise. Some of the 

issues that need to be understood are:

 The camera cannot be used during rain or fog and can be difficult to use with overcast 

skies.

 Some cameras are not intrinsically safe (do not meet NEC Class 1 Div. 2 criteria) and 

require a hot work permit. 

 Interferences - Infrared cameras can pick-up water vapor and if the operator is unaware 

that the source is water vapor, it can be mistaken for a leak of hydrocarbon.

 Camera sensitivities and detection threshold for different components 

 Precision / accuracy / resolution

 Minimum training requirements and operator certification

For voluntary programs or programs designed to locate potential leaks, an IR camera is faster at 

checking for leaks, as noted in the EPA White Paper. There are multiple estimates as to the rate 

of screening components by OGI, which could be as high as 2,000 components per hour for 

equipment dense facilities such as refineries. In comparison, the average screening rate using a 

handheld TVA or OVA is roughly 300-400 valves per day with their associated connectors. FLIR 

claims that it can scan 3,000 components per day versus 500 for Method 21, but the bottom 

line is that for small, geographically dispersed facilities that would still just amount to 1 well site 

per day. Clearstone 2006 found that OGI was 3 times faster than Method 21 to screen for leaks 

(for two people 2,400 components per day for conventional versus 6,400 components per day 

for the optical.) Furthermore, the OGI is potentially better at finding leaks than Method 21. The 

Picard, et al., 2006 Study (06-A-119-AWMA) found that of the ten largest emission points shown 

in Table 5 of the paper, only five of them were detected by traditional (Method 21) screening 

methods while eight were found by optical gas imaging. The two leaks that were identified by 

Method 21 but not by the OGI camera were large enough to be detected but were missed by 

the camera operator. Also, one has to note that the mid-infrared camera used in that study was 

an early prototype. Modern cameras would have identified leaks more easily. 

However, the trade-off for speed is capital cost. Additional cost data for the cameras, calibration 

and maintenance, and training are needed directly from operators or turn-key vendors. Some 

typical costs include: 
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 FLIR GF Series cost – $85,000 - $100,000+ (packages that include many peripherals can 

cost >$125,000, day rates ~ $500/day - $2000/week)

 Batteries, chargers, other required peripherals can add $5k - $10k 

 Annual service contracts - $5k - $10k

Training cost for FLIR camera operators - ~$2000/level and 3 levels – a total of ~$6000 

(http://courses.infraredtraining.com/) or onsite training by FLIR ~ $17,000 for up to 12 students 

(3-day course).

D.1.3. Acoustic Leak Detector

To our knowledge, acoustic leak detection is not currently being used at onshore oil and gas 

production facilities. Furthermore, ultrasonic detectors are only effective in areas with low 

background noise levels in the ultrasonic range which greatly limits their usability. Since the EPA 

presents no cost data for acoustic leak detectors and the single study cited (URS/UT, 2011) 

concluded that acoustic detectors were not considered to be an ‘accurate alternative’ to direct 

measurement, additional data needs to be developed to show tangible benefits to using this 

technology before serious consideration of this technology is undertaken. 

D.1.4. Ambient /Mobile Monitoring

Ambient/mobile monitoring for equipment leaks has numerous problems associated with it. 

Application of this method depends on the formation of a well-developed atmospheric plume, 

detectable at ground level, downwind of the site. Only a fraction of sites are amenable to this 

type of sampling, depending on downwind access, meteorological conditions, which may vary by 

season, as well as topographic conditions. The resulting measurements represent an aggregate 

of emission sources upwind of the measurement device. As a result, the measurements cannot 

be used to assess emissions from an individual source, facility, or plant. Tracer gas is used to 

isolate emissions from a specific location, where there is an assumed equivalent dispersion of 

the tracer and methane. 

Measurements from these studies generally reflect a specific point in time, and are therefore 

not representative of annual emissions. The specific study cited in EPA White Paper 2.8 

conducted measurements over 20 minute “snapshots” at locations where the highest methane 

concentrations were observed.

In the White Paper, EPA stated that “mobile leak detection techniques might be best used in 

conjunction with OGI technology; an OGI inspection would be triggered by the detection of 

above normal emissions by the mobile leak detection technique.” However, such an approach is 

likely to cause unnecessary OGI inspections due to the following limitations:

 The mobile leak detection techniques may detect methane from some up-wind source, 

but the technology cannot pinpoint specifically where the methane is coming from 

because it depends on meteorological and geographical conditions at the time and 

location of the measurement.
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 The mobile leak detection techniques capture a specific point in time. Some GHG 

emission sources result from episodic events that could be detected from the mobile 

monitoring but would not be detected in an OGI at a later/different time.

The number of locations where mobile leak monitoring could be used to reliably identify a site 

for follow-up OGI survey is extremely limited. 

The cost information represented in EPA’s White Paper seems too low for the full equipment set 

required. The source of the information used by EPA to develop these costs is not documented 

and the study cited in EPA White Paper 2.8 did not include cost information for the 

measurements conducted. Additional information on this technology needs to be gathered 

before serious consideration of this technology is undertaken.

D.2. Additional Techniques EPA Should Consider

Discussed below are the AVO method for detecting leaks and the maintenance program for 

minimizing leaks that EPA should also include when considering and evaluating the mitigation 

options for leak emissions.

D.2.1. Auditory, Visual, and Olfactory (AVO) Method for Leak Detection

The EPA White Paper did not consider the impact and cost-effectiveness of AVO leak detection. 

This may be the most efficient and under-valued method of leak detection. As discussed in 

Section B.2 previously, the AVO inspections have long been considered the backbone of any 

good inspection program. They are reliable for identifying the most obvious and significant 

emissions release events. It would be difficult to quantify the impact from countless operators 

who find and fix leaks every day simply because ‘it’s their job’ and not because of some 

regulatory mandate. While difficult to quantify, the EPA should not ignore the efforts of 

operators who maintain a culture that values proactive attention to leak detection and repair, 

regardless of regulatory requirement. Responsible operators who proactively address such 

problems would be inappropriately penalized if a mandated leak inspection program were 

imposed. They would be forced to implement a costly program (inspection, recordkeeping, and 

reporting) that would return little or no additional environmental benefit just to remain 

compliant.

D.2.2. Leak Prevention – Preventive Maintenance Program

Also overlooked in the EPA White Paper are the impacts of preventative maintenance (PM) 

efforts. These efforts include periodic inspection and service of components that are not 

leaking, material selection appropriate to service (i.e., alloys, gaskets, filters, etc. that are wear 

and/or leak resistant), active corrosion monitoring, the application of corrosion and scale 

inhibitors, use of maintenance records to identify components at risk of failure, and pre-emptive 

replacement of at-risk equipment.
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In considering any leak inspection and repair mandate, the EPA should recognize that, in this 

case too, operators whose PM programs are robust and effective would be penalized by having 

to implement an inefficient program to look for leaks where few may be found. 

See additional discussion in Section B.3, Preventive Maintenance Program above.

E. Repair: Cost and Cost-Effectiveness 

EPA’s review of the repair cost and the cost effectiveness analysis involved no independent data 

gathering, merely a summary of the findings of other studies. There was no validation of the data 

presented in these studies or confirmation that the cost estimates were realistic or reflect current costs. 

Although there are multiple references to “Economic Analysis of” and “Cost-Effective...” methods of 

emissions reductions through DI&M and LDAR-type inspections, cost data cited in the EPA White Paper

are mostly costs associated with repairing the leaking components, not including the cost for finding 

those leaks. The data that are presented have not been independently verified. For example, the costs 

cited for OGI surveys (Carbon Limits, 2013) are sourced from two private sector service providers who 

are positioned to realize substantial financial benefit if a comprehensive instrument-based leak 

inspection programs are mandated. In addition, cost data were presented without referencing the age 

of the data (e.g.,Table 3-5 in the White Paper) and many of the references citing ‘cost-effectiveness’ 

based those conclusions on outdated natural gas pricing.

E.1. Cost Considerations

The studies cited by EPA mostly ignored the cost to find the leaks and simply focused on the cost 

to repair the leaks. Even when the cost for hiring a leak survey service provider was mentioned, 

other costs associated with leak detection and repair were not adequately represented to reflect the 

true cost burden to the owner/operator. In fact, in the Carbon Limits study, they found that when 

the cost of leak detection was included, the majority of the sites were uneconomic to repair. EPA 

must include all the following costs in performing an analysis of the cost effectiveness: planning and 

setup; leak detection; repair; recordkeeping and potentially reporting; and costs incurred due to the 

remote, dispersed, and unmanned nature of facilities. In addition, a cost effectiveness analysis 

should not be performed across the entire oil and gas industry; rather, one analysis should be 

conducted for each of the different types of facilities, e.g., production pads, tank batteries, 

gathering compression stations, gas plants, transmission stations. All the cost consideration factors 

listed above are further discussed as follows. 

 Cost for planning and setup

There is a considerable amount of work that must be done to set up an inspections or 

monitoring program, including:
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o Developing an LDAR or other monitoring plan that covers responsible parties, 

training including health and safety training, certifications of monitoring personnel, 

quality assurance procedures to ensure appropriate equipment selection and 

calibration, identification of components, monitoring frequency and methodology, 

repair strategy and timeline, and recordkeeping and reporting. 

o Getting actual counts of the components at each facility, 

o Numbering and tagging the components if required by the regulation,

o Maintaining the integrity of the tagging system (e.g., replacing missing tags due to 

weathering, component replacement, etc.)

o Setting up data management system that can acquire the information from the 

monitors, set up the information data base, compile the information in a data base, 

develop required reports from the data, etc.

o Determining the repair strategy and timeline

o Selecting and hiring the monitoring staff

o Selecting and hiring the repair staff

o Selecting and hiring the database entry and management staff

o Selecting and hiring the recordkeeping and reporting staff

Studies cited by EPA included no review or analysis of the cost for any of the above items. 

The CL, 2013 study simply made a gross assumption to cover all those items (50% of the cost 

of hiring contract monitoring service for “administration, paperwork”), which was not nearly 

adequate to reflect the true cost burden to the operators. 

 Cost for leak detection

Companies have the option of either using a contract service to do the monitoring and/or 

repairs for them or having in-house staff to do the monitoring and/or repairs. The cost of a 

monitoring contractor service can vary depending on the services that the company 

provides, the level of expertise of the staff, the amount of competition the company has in a 

particular area, the time to do the monitoring per location, and the distance and travel cost 

between locations. 

If a company chooses to do in-house monitoring then they must incur the cost to properly 

train the staff on use of the leak detection equipment, purchase the leak detection 

equipment, maintain the equipment, calibrate the equipment, cover the cost of the labor to 

do the detection, and cover the cost of transportation and time between locations. In the 

White Paper, EPA only provided the equipment cost for the portable analyzers and 

ambient/mobile monitoring. In addition to the equipment cost, the actual leak detection 

cost should also include all the items listed here.

As shown by the Carbon Limit study, the majority of sites are uneconomic to do repairs on 

leaks if the cost for leak detection is added. 
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 Cost for repair

In the White Paper, EPA summarized the cost presented in the referenced studies for 

repairing individual components. However, they did not compare the cost between using a 

LDAR contractor service versus doing the repairs in-house. Furthermore, cost was not 

discussed for monitoring the equipment after the repair to confirm that it was repaired. 

Also, EPA must consider the cost of time for operators or leak survey contractors to drive to 

the locations to do the repairs for dispersed, unmanned locations. Much of the cost data 

presented were from older studies and the information would be greatly out dated.

The cost of repair is fixed for a given component, i.e. a 1⁄2 in gate valve”, however not all 

repairs are equivalent. The cost to remove the valve for repair is greater than if the valve 

can repaired in place. None of the studies EPA reviewed considered the variation in cost 

depending on what was required. 

None of the studies cited by EPA included the cost, possibly the most significant cost, for 

having to shut in wells or other facilities and purge the equipment in order to do the repairs. 

Any repair involving hot work (such as welding) or equipment replacement will generally 

require the production facilities to be shut in per safety procedures. Most companies do not 

allow hot work on equipment without it being shut in and completely purged, as most 

upstream facilities are not designed with redundant or bypass capability. The emission 

reductions achieved from the repair would have to be weighed against the amount of gas 

purged from the equipment. Also, the cost would need to include the lost production from 

shutting in the well or cost of lost operations from shutting in a facility such as the cost from 

lost processing at a gas plant.

 Cost for recordkeeping and potentially for reporting

The recordkeeping requirements of most LDAR programs are the most laborious part of 

the program. For the traditional EPA Method 21 monitoring, each component must be 

individually tagged and noted in a system that tracks the readings, the repairs, and the 

re-readings of the component. A data management system must be set up that can 

acquire the information from the monitors, set up the information data base, compile the 

information in a data base, develop required reports from the data, etc. Robust data 

management systems are very expensive and add significantly to the overall cost of a

monitoring program. Surcharges from turn-key contractors to pay for these systems often 

add significantly to the overall cost of the program. For dispersed, unmanned sites, 

keeping tags on components and tracking all the records of readings, repairs, and rereadings will be extremely onerous and difficult. The cost of such a monumental effort 

would be extremely high.

 Remote, dispersed and un-manned nature of the industry
API Comments on Submitted to EPA

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The vast majority of oil and gas facilities are located away from population centers (remote), 

far from one another (dispersed), and do not have personnel stationed at the site (unmanned). Operators, maintenance crews, and monitoring teams often have to travel 

significant distances to reach a site, incurring significant additional costs than those of 

chemical and refining plants. Inspection and maintenance visits occur on average anywhere 

from weekly to twice per month, depending on location and time of year. In some areas, 

winter weather makes it difficult to visit sites. Sites can be as far as an hour apart which can 

limit the number of locations that can be monitored each day. Historical LDAR programs 

have been at refineries, chemical plants, and large gas processing plants using Method 21 

where contracted LDAR monitoring teams, many times located on-site, perform the leak 

detection, and then work orders are created to do the repairs by the on-site operators. 

Drive time and transportation is not an important factor in refineries and chemical plant

programs as it will be for dispersed, unmanned oil and gas sites.

 Separate the cost analysis for processing plants, gathering compressor stations, tank 

batteries, and well production facilities.

Cost-effectiveness analyses should be performed separately for gas processing plants, 

gathering compressor stations, tank batteries, and well production sites because the cost for 

each group of these facilities is different. Specifically, instrument-based inspections at 

remote, dispersed upstream facilities will be substantially less cost-effective than 

instrument-based inspections at other facilities, considering the following issues and typical 

costs:

o Vehicle mileage costs ($0.65/mi)

o Equipment day-rates (OGI ~ $500/day)

o Labor rates for qualified technicians ($40 - $85 / hr)

o LDAR engineers – ($100-$140/hr)

o LDAR Project Manager – ($100-$190/hr)

o Mobilization / demobilization to remote sites

o Leak rates and frequencies appear to be much lower at well sites well batteries 

(more likely to be remote and dispersed) than other facilities (Carbon Limits, 2013, 

and UT, 2013)

Actual cost data from implementation of emerging state programs, such as, Colorado’s Regulation 7 

and Ohio’s Oil and Gas General Permit, over the next two years may provide critical information 

needed to evaluate the cost-effectiveness of production site LDAR programs.

E.2. Cost-Effectiveness Analyses in Previous Studies

Under Section 3.2 of the White Paper, Repair, EPA presented a summary of five studies/documents 

to demonstrate various approaches to deciding whether to repair the leaks found during the surveys 

or not, provided repair is not mandatory. Examples of the approaches included the net present 

value (NPV) analysis, and the payback period analysis. EPA did not offer a critical review or 
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verification of the cost data and the analyses in those studies, nor did EPA independently collect cost 

data and perform an analysis. API has provided its review and comments related to the emissions 

issues in those studies in Section C, which will not be repeated here. The most significant and 

salient points with regard to leak repair cost and effectiveness are discussed below. API’s comments 

on EPA’s inclusion of the Natural Gas STAR lessons learned documents are presented in Section 

E.2.4. In addition, EPA’s Technical Support Document (TSD) developed in support of the NSPS 

Subpart OOOO is briefly discussed in Section E.2.6.

E.2.1. EPA White Paper 3.2.1 - Quantifying Cost-Effectiveness of Systematic Leak 

Detection and Repair Programs Using Infrared Cameras (Carbon Limits, 2013)

This study provided an analysis of 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. As noted 

above, a general summary and API’s comments on the emissions related data in this report are 

discussed in Section C. API’s cost related comments are enumerated below.

(1) Emissions identified in the survey and included for cost-effectiveness analysis include 

emissions from vents. In fact, vents are the most common source of gas emissions from 

all emission sources identified in this study. As EPA noted on p. 29, vented emissions 

are not considered leaks for the purpose of this White Paper.

(2) The study made the unfounded assumption of the cost for hiring a service provider to 

survey the facilities (“external cost”), and assumed without any basis in fact that there 

would be only an additional 50% of it to account for so-called “internal cost” such as 

administration, paperwork, etc. Many of the cost data elements such as initial set-up 

costs, operator training, program oversight, and reporting burdens, as discussed in 

Section E.1 above, were not considered.

(3) The data for this study (leak rates and costs) were provided by two private sector firms 

(Target Emission Services and Greenpath Energy Ltd) – both whose primary business is 

providing LDAR services to the oil and gas industry. The statement “...the overall cost... 

will always be relatively low because surveys are relatively inexpensive” is unsupported,

and not a statement of fact. The costs provided by these two vendors were not verified 

independently nor was any attempt made to make regional adjustments to the costs.

(4) As EPA noted in the White Paper, “... when compared with the cost of monitoring ..., the 

economic benefits of repairing the leaks at most facilities are less than the total of the 

survey.” Considering (1) and (2) above, the cost/benefit ratio of monitoring appears to 

be higher than acknowledged by this study.

(5) For well sites and well batteries, the study estimated that 81% of the sites had a 

negative NPV for repairing all identified leaks. However, when all of the individual well 

sites and well batteries are aggregated into a group, the aggregated NPV is positive. It is 

not reasonable to aggregate facilities in looking at cost. Many facilities are not near 

other facilities and typically only one site can be monitored in a day. Some companies 

only have one site in an area. Because of the inherent variability in facilities, allowing 
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operators to determine the optimal schedule including setting priorities and frequency 

for inspections will be crucial to the success of any leak detection and repair program.

(6) With all vented emissions excluded and additional cost data elements included as they 

should be, it is not likely that even the aggregated NPV would be a positive number.

(7) In the study, the cost of repair is assigned a fixed range for a given component type

(e.g., valve, connector), however the costs are estimated by survey companies, not 

facility operators. Most third-party vendors estimate only the superficial cost of repair 

and fail to account for the total cost burden shouldered by the operator. The cost to 

remove the valve for repair is greater than if the valve can be repaired in place. The 

study does not consider the cost for shutting down the facility, purging the equipment, 

and loss of production or processing as discussed in E.1 above. Most facilities do not 

allow for hot work and must be shut down and purged for repair.

(8) The OGI survey cost estimates ($1200 for multi-well batteries, $600 for a single well 

battery, and $400 for a well site) are not documented and are not likely to be validated 

if subjected to rigorous review. The actual cost seen by API companies for doing OGI 

surveys for sites have been several times what this study is claiming.

(9) Cost data developed for OGI surveys on individual well sites by some API members show 

great variation in ‘per unit’ cost depending on many factors, including location,

qualification of inspection personnel, and competition for quality service providers in 

the area. 

(10)EPA failed to capture that the study found that “Increasing the frequency of surveys

...will increase abatement cost.” Unfortunately, the study only looked at the aggregate 

cases not the cost on a per site basis. 

(11)Based on API members’ experience, we believe the cost estimates provided in this study 

are overly optimistic and underestimate the real costs. The assumptions of the cost 

components probably are not inclusive of many of the other factors enumerated in 

Section E.1 above. 

E.2.2. EPA White Paper 3.2.2 - Identification and Evaluation of Opportunities to 

Reduce Methane Losses at Four Gas Processing Plants (Clearstone, 2002)

This study (Clearstone I) provided analysis of the payback periods for repairing the identified 

leaks. EPA recognized that the repair economics did not include the cost of the leak detection 

survey, and only included the income of gas recovered and the cost of repair. 

(1) The purpose of this study was to identify the opportunities for industry to cost 

effectively reduce methane emissions for voluntary programs, such as the Natural Gas 

Star Program. The costs of repairs were designed to be realistic, but did not include 

many of the costs that are often incurred in a regulatory program, such as rigid repair 

timeframes, and recordkeeping and reporting burdens. For example, the Picard, et al., 

2006 study (06-A-119-AWMA) found that 320 of 423 leaks were economically 

repairable. Clearstone I and II did not compile this statistic, but that analysis would 
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certainly show similar results. However, including all of the costs discussed above in 

Section E.1, the result would be significantly longer payback periods and far fewer 

‘economically repairable’ leaks.

(2) The analysis is based on data from four gas processing plants only where maintenance 

personnel are available on a regular schedule incurring no travel time to complete the 

repair. The analysis does not consider remote and dispersed facilities common in the 

upstream industry as described in Section E.1 above. No data were collected for 

production sites, tank batteries, or compressor stations.

(3) In addition to leaks as defined in traditional LDAR programs, many other sources of 

emissions are also included, such as flaring, combustion equipment, storage tanks, etc.

(4) The payback periods analysis approach does not take into account the cost of the leak 

detection survey and all other cost data considerations discussed in Section E.1 above, 

and so it does not reflect the true cost burden for the facility owner or operator. For 

instance, repair costs are fixed cost for each type of component. Typically, costs 

estimated in this way fail to capture the entire cost burden associated with facility 

shutdowns, lost production, and other costs detailed in Section E.1 above.

(5) Some of these uniquely upstream costs can be mitigated, if the timing of the repair can 

be planned so that several repairs and other operations that require process shutdowns 

can be coordinated. Programs that include flexibility in repair schedules and a delay of 

repair provisions can improve cost-effectiveness of leak mitigation efforts.

(6) The cost data is over 12 years old and not representative of current costs.

(7) These comments are also applicable to the Clearstone II study, discussed in EPA’s white 

paper in section 3.2.3. 

E.2.3. EPA White Paper 3.2.2 – Cost-Effective Directed Inspection and Maintenance 

Control Opportunities at Five Gas Processing Plants and Upstream Gathering 

Compressor Stations and Well Sites (Clearstone, 2006)

This is a follow up on Clearstone I study.

(1) The study included five gas plants, seven gathering compressor stations, and twelve well 

sites. However, the data presented in the report were grouped into five “sites”, labeled 

as Sites 1 to 5. There is no explanation about the numbers of gas plants, gathering 

compressor stations and well sites that are included at each “Site.” As a result, both the 

emissions and the cost-effectiveness analyses were performed with data from all three 

types of facilities aggregated together. 

(2) As stated earlier, API believes that cost-effectiveness analysis should be performed 

separately for gas plants, gathering stations, and well sites. It is mainly because the 

concentration of equipment components at gas plants is higher than that at production 

sites, resulting in different cost considerations.

(3) In addition to leaks as defined in traditional LDAR programs, many other emission 

sources, such as vents, are included.
API Comments on Submitted to EPA

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(4) The assumed gas price in this study was $7.15 per Mcf, which is more than 32% higher 

than $5.40, the average Henry Hub natural gas spot price from January 2001 to April 

2014.

(5) The costs of leak detection surveys were not included in the cost consideration, nor 

were many other costs discussed in Section E.1 above.

(6) The cost data is over 8 years old and not necessarily representative of current costs.

E.2.4. EPA White Paper 3.2.4 - Natural Gas STAR Directed Inspection and 

Maintenance (EPA 2003a, EPA 2003b, and EPA 2003c)

Without qualification, the EPA White Paper’s lead sentence of Section 3.2.4 states, “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, U.S. EPA 2003c).” However, on closer examination of the referenced 

documents, API believes this statement needs to be significantly qualified and presented in the 

appropriate context.

The Natural Gas STAR lessons learned documents referenced in the White Paper address three 

separate industry sectors:

 DI&M at Gate Stations and Surface Facilities (U.S. EPA 2003a) which addresses 

equipment at gate stations and equipment for gas distribution to consumers 

downstream of the gate stations;

 DI&M at Compressor Stations (U.S. EPA 2003c) which focuses on natural gas pipeline 

transmission compressor stations; and

 DI&M at Gas Processing Plants and Booster Stations (U. S. EPA 2003b).

As stated in the Introduction section, API’s comments presented in this paper focus on oil and 

natural gas production, gas gathering, and gas processing operations. Therefore, it is only the 

third Natural Gas STAR lessons learned document listed above (U.S. EPA 2003b) that API has 

reviewed closely. While the title of this document lists “booster stations”, no data from any 

stand-alone booster station was included in the analyses. The data developed was from a very 

limited 4-plant (all gas processing) pilot study and an additional 2-plant (both gas processing) 

study by Natural Gas STAR partner Dynegy. 

In addition, specific language in all three of the Natural Gas STAR lessons learned documents

stress the unique nature of each facility, for example:

 “Operators should develop a DI&M survey schedule that... suits the unique 

characteristics and operations of their facility.” (U.S. EPA, 2003b, pg. 9)

 Under Lessons Learned, “No two gas processing plants are alike. Opportunities for costeffective gas savings will vary widely depending upon such factors as the age and size of 

the facility, types of plant components, and the operating time since the last major plant 

maintenance.” (U.S. EPA, 2003b, pg. 10).
API Comments on Submitted to EPA

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39

EPA states in the section 3.2.4 of the White Paper that “from previous field studies conducted by 

the EPA and Natural Gas STAR partners, the EPA has observed that typically 20% of the top 

leaking components account for approximately 80% of the emissions from a facility”. This is 

consistent with previous findings discussed above that 81% of monitoring has negative NPV. 

Moreover, because the programs instituted under Natural Gas STAR are voluntary, the authors 

of these papers clearly intended that their recommendations for implementing DI&M programs 

be flexible and voluntary, so that each operator could design a program that would be most 

effective and appropriate for its unique operations and equipment. Since the nature of the 

Natural Gas STAR program is to recognize ‘star’ performers – those operators who are in a 

position to achieve such a performance rank cannot be considered the norm. Only the projects 

with the most significant emissions reductions are selected and it is not realistic to expect every 

operator would be in a position to achieve the same results, given differences in location, 

resources, facility age, asset profile (mix of upstream and midstream facilities) and many other 

factors. The cost effectiveness factors cited in these documents are not likely to reflect the 

typical or average factors that could be achieved under a regulatory program. Using these ‘star’ 

performers as a learning experience is appropriate but assuming that they could serve as a 

template for regulatory action is misguided.

Finally, in the EPA White Paper, Table 3-5 (pg. 49) is adapted from Exhibit 5 from the Natural Gas

STAR paper on gas processing plants and booster stations (U.S. EPA 2003b). There are two 

problems with this table. First, the Average Component Leak Factor (Mcf/yr/component) cited 

in the EPA table is a Methane emission factor, while in the EPA White Paper incorrectly labels it 

as “Total”. Second – and more concerning – the costs cited are at least 11 years old and the age 

of those cost data are not noted, cited, or discussed.

EPA’s unqualified assertion that ”...the Natural Gas STAR program recommends implementation 

of a DI&M program to economically reduce methane emissions from leaking components” is

misleading. Given the limited scope of the facilities covered by the Natural Gas STAR lessons 

learned documents, the voluntary nature of the recommended DI&M programs, and the stated 

‘lesson learned’ that each facility is unique and each DI&M should reflect that uniqueness, EPA’s 

statement needs to be accurately qualified, cited, and interpreted.

E.2.5. EPA White Paper 3.2.5 - Update of Fugitive Equipment Leak Emission Factors 

(CAPP, 2014)

This report compares the fugitive equipment leak emission factors derived from data provided 

by upstream oil and gas facilities in Alberta and British Columbia, Canada both before and after 

implementing the DI&M BMP programs. The authors concluded emissions from leaks have 

decreased by 75% among the participants since the implementation of the DI&M programs. 

There were no discussions on cost and cost-effectiveness of implementing such programs. 
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E.2.6. NSPS Subpart OOOO Technical Support Document (TSD) (U.S. EPA, 2011 and 

2012)

During the rulemaking of NSPS Subpart OOOO, EPA developed the background technical support 

document (TSD) in which EPA described the emission sources in the oil and gas sector being 

considered for regulation, estimated emissions, identified control options for emission reduction 

and their costs, and provided EPA’s rationale in the final rule. EPA published the TSD for the 

proposed rule in July 2011 and revised it in April 2012 when finalizing the Subpart OOOO rule. 

Equipment Leaks were discussed in Chapter 8 of the TSD. These TSDs focused on VOC emissions 

from the new facilities as defined in the rule with some data on methane emissions also 

presented. 

In the 2011 TSD for the proposed rule, EPA included cost for well pads for Method 21 on Table 

8-13 showing that it is not cost effective to do Method 21 monitoring at well pads because the 

cost is as high as $267,386/ton of VOCs. Method 21 at a well site is clearly unreasonable from a 

cost perspective but also from the work involved. Method 21 typically requires the third party 

contractors who are specially trained in doing the monitoring. Each fugitive component must be 

tagged and monitored separately.

Table E-1: Summary of the Model Plant Cost Effectiveness for the Subpart VVa Option

(from the 2011 Subpart OOOO Proposed Rule TSD)

Model 

Plant

Annual Emission Reductions

(tons/year)

Capital 

Cost ($)

Annual Cost

($/year)

Cost Effectiveness

($/ton)

VOC HAP Methane without 

savings

with 

savings

VOC HAP Methane

Well Pads 

1 0.0876 0.00330 0.315 $15,418 $23,423 $23,350 $267,386 $7,088,667 $74,253 

2 2.43 0.0915 8.73 $69,179 $37,711 $35,687 $15,549 $412,226 $4,318 

3 25.3 0.956 91.3 $584,763 $175,753 $154,595 $6,934 $183,835 $1,926 

It should be noted that the Well Pad Model Plant 3 in the table above is based on a well pad 

with 48 production wells. While a well pad with that many production wells may exist, it is 

definitely not representative of any oil and gas operations in the continental U.S. 

In the 2012 TSD for the final rule, EPA presented a different analysis. Even though API does not 

agree with EPA on many aspects of the analysis in this document, it still showed that it is not 

cost-effective to require NSPS LDAR programs (e.g., Subparts VV or VVa) for production well 

pads or gathering and boosting stations. The analysis results for well pads and gathering and 

boosting in the 2012 TSD are shown below (from Table 8-4 in the 2012 TSD):
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Table E-2: Summary of VOC Cost Effectiveness of the LDAR Options

(from the 2012 Subpart OOOO Final Rule TSD)

LDAR Option

Total Capital 

Investment

Annual LDAR Cost 

($/Yr)

VOC Emission 

Reduction

(Tons/yr)

VOC Cost 

Effectiveness

($/Ton of VOCs)

Well Pads

V/VV $101,100 $55,365 6.95 $7,964

VVa $102,534 $57,534 7.80 $7,379

Gathering & Boosting

V/VV $374,334 $135,821 31.8 $4265

VVa $379,571 $143,807 34.8 $4131

Examples of API’s major concerns with the Subpart OOOO TSD include:

 Both the 2011 and the 2012 TSD used the cost data from the chemical and refining 

industry in the analysis. For example, in the 2012 TSD, EPA primarily adopted the cost 

data in the analysis performed for the development of the Uniform Standards for 

Equipment Leaks, which was based on three model plants for the chemical industry and 

three model plants for the refining industry.

 The cost data did not account for all the cost considerations discussed in Section E.1 

above.

 The emissions data and estimates were primarily based on the outdated, decades old 

studies, including 1996 GRI/EPA study (1992 base year).

Notwithstanding all API’s concerns, the TSD analysis still showed requiring an LDAR program

similar to that in NSPS VV or VVa is not cost effective for oil and natural gas production or 

gathering and boosting facilities.

F. Summary 

In the Summary section of the White Paper, EPA attempted to summarize “characteristics that the 

Agency believes are important to understanding this source of VOC and methane emissions.” API 

disagrees with the following points that EPA made:

 EPA cited the 2014 GHG Inventory estimates as the potential methane leak emissions from the 

oil and gas sector, which does not represent the current emissions level. EPA has

acknowledged in the past that their use of the 1996 GRI/EPA emission factors (for 1992 base 

year) as the basis for developing the GHG Inventory rendered the estimates only representative 

of the potential emissions, i.e., what emissions would be if practices and technologies had not 

changed over time. EPA should make an effort to estimate what the true, net emissions are

from leaks in order to understand this source of VOC and methane emissions, especially since 

most recent two studies on leaks from production facilities show many facilities with no 

detectable leaks and a very low average leak rate per site. 
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 EPA indicated that, “currently, portable analyzers provide an effective approach for both 

locating and measuring the concentration of leaks from oil and natural gas production sites.” 

However, EPA’s analyses in the NSPS Subpart OOOO TSD’s (U.S. EPA, 2011 and 2012) showed 

that an LDAR program requiring the use of portable analyzer, such as the one in NSPS VV or 

VVa, is not cost-effective for oil and gas production sites. 

 EPA stated that “ambient/mobile monitoring and OGI technology might be most effective when 

used in tandem,” and that “an OGI inspection would be triggered by the detection of above 

normal emissions by the mobile leak detection technique.” However, such an approach is likely 

to cause unnecessary OGI inspections due to the limitations of this method. The number of 

locations where mobile leak monitoring could be used to reliably identify a site for follow-up 

OGI survey is extremely limited. Furthermore, it requires buying or paying for a contractor to 

use both types of equipment making it uneconomical.

 API disagrees with the statement that “available information suggests that once a leak is found 

it is almost always economical to repair the leak.” It is not economical when the leak detection

cost and all other costs discussed in Section E1 are included. As discussed earlier in this 

document, some of studies cited by EPA showed very low equipment leak emissions, resulting 

in only $1.79/day/site (UT, 2013), or $3.11/day/site (Carbon Limits, 2014) of natural gas loss 

from equipment leaks at production sites. When separate trips are necessary for repair and/or 

re-monitoring to ensure repair at remote, dispersed and unmanned production sites, it is 

unlikely the repair would be economical. 

G. Conclusions and Recommendations

Based on the foregoing, API reached the following conclusions and recommendations for EPA:

 In the White Paper, EPA defines leaks as VOC and methane emissions not only from equipment 

components that are traditionally covered in the LDAR programs under NSPS and NESHAP 

regulations, but also from incidents where, for example, storage thief hatches are left open or 

separator dump valves are stuck open. 

 Emissions resulting from such incidents have not been well documented or characterized, but may 

emit at higher emission rates than emissions from equipment component leaks. Most of the 

incidental emissions are caused by equipment failure, dirty process fluids, lack of maintenance, or 

operator error. Typically, these incidental emissions can be easily identified through operator’s 

routine checks on process equipment using sensory inspection methods in a timely manner. 

However, a traditional LDAR program is not efficient in identifying incidental emissions, because 

Method 21 is designed to detect leaks from cracks or mated/sealed connections while incidental 

emissions often occur at thief hatches, vents, or sumps.
API Comments on Submitted to EPA

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 Emissions from leaks as defined by EPA in this White Paper (including both traditional fugitive 

emissions and incidental emissions) have not been reliably quantified, estimated, or documented 

either at a facility level, or at a regional or national level. 

 “Leak” emissions data and emission estimates historically only include fugitive emissions from 

equipment and do not include incidental emissions. For example, the 1995 Protocol (EPA, 1995), 

the GRI/EPA Study (GRI/EPA, 1996), the GHG RP (EPA, 2013), and the GHG Inventory (EPA, 2014). 

While the uncertainty in emission estimates for incidental emissions is substantial, even considering 

only fugitive equipment leaks, accurate emission estimates do not exist because elements such as 

emission factors and representative component counts are outdated and not representative of the 

broad range of oil and gas production facilities currently in operation.

 Accurate emission estimates are crucial to reasonable cost-effectiveness analyses for mitigation 

options. As the first step, EPA should focus on improving estimates of leaks emissions, including 

both fugitive equipment leaks and incidental emissions. For example, the fugitive equipment 

emissions can be improved by obtaining accurate component counts at well sites, tank batteries, 

and compressor stations, as well as emission factors that apply to those facilities.

 As EPA noted correctly and repeatedly, vented emissions are not leaks for the purpose of this White 

Paper. Most, if not all, the more recent studies cited by EPA included vented emissions. Examples 

include the Greeley, CO study (Modrak, 2012); the Carbon Limits’ study (Carbon Limits, 2013); the 

Mobile Measurements studies in CO, TX and WY (Thoma, 2012); and the Clearstone I (Clearstone, 

2002) and Clearstone II (Clearstone, 2006) studies. Therefore, the economic analyses based on 

emissions data in these studies likely overestimated emissions and should be scrutinized carefully to 

determine whether they truly represent the economics for repairing leaks as defined by EPA in this 

White Paper. 

 In analysing the cost-effectiveness of a leak detection and repair program, the cost for implementing 

the program as well as the remote, dispersed and unmanned nature of the industry has not, but 

should be, considered. See detailed discussion in Section E.1.

 Two of the most relevant general conclusions for leaks at oil and gas production sites reached by the 

various emissions studies cited by EPA are:

1. Predominantly high percentage of total facility leak emissions are due to very few

highly leaking components; and

2. Leaks at production sites are typically low in volume and frequency, challenging the 

conclusion that an LDAR-type ‘find-and-fix’ program is always cost effective. For 

instance, a recent study (UT, 2013) suggests that one third of production sites had no 

detectable leaks and that, of the 66% sites that had any detectable leaks, the average 

total emissions (both leaks and vents) per site were 0.23 standard cubic feet per 

minute. This is only 330 scfd per well site. At $5.40 per thousand cubic feet (Mcf), this is 

a natural gas loss of $1.79 per day. Another recent study (Carbon Limits, 2014) suggests 
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an average leak emissions rate per site of 0.4 scf/min (leaks only, not vents). This is 576 

scfd/well site and lost natural gas value of $3.11 per day per site. 

 In evaluating various leak emissions mitigation techniques, EPA has not, but should, include sensory 

(or AVO) inspections and preventive maintenance programs. Sensory inspections have long been 

considered the backbone of any good inspection program. They are reliable methods for identifying 

the most obvious and drastic problems. Preventive maintenance programs are a proactive measure 

to minimize the occurrence of both types of leak (incidental emissions and fugitive equipment 

leaks). It is in contrast with the reactive approach of the traditional LDAR program (waiting for a 

leak to happen, finding it, and then fixing it). 

 Based on the very low reported methane losses per well site (UT, 2013; Carbon Limits, 2014), a lowcost and integrated approach to addressing both the fugitive equipment leaks and the incidental 

emissions should be considered by EPA for any future cost-effectiveness analyses. One such 

approach is a preventive maintenance program which allows the use of sensory inspections. It can 

reduce the occurrence of both types of leaks more effectively than a reactive “leak detection and 

repair” program. 

H. Charge Questions

Most of the issues raised by the Charge Questions for Reviewers in the EPA White Paper (Section 5) have 

been discussed in previous sections of this document as listed below:

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? 

Refer to Sections B, C and E.2. No, the White Paper authors simply summarized studies with no 

critical analysis of the validity of the information within them. 

As summarized in the Conclusions and Recommendations above, emissions from leaks as 

defined by EPA in this White Paper (including both traditional fugitive emissions and incidental 

emissions) have never been reliably quantified, estimated, or documented either at a facility 

level, or at a regional or national level. As acknowledged in the studies referenced in the White 

Paper, “leak” emissions data and emission estimates historically only include fugitive emissions 

from equipment and do not include incidental emissions. Clearly the uncertainty in the 

estimates of incidental emissions is substantial, but even considering only fugitive equipment 

leaks, accurate emission estimates do not exist because elements such as emission factors and 

representative component counts are outdated and not representative of the broad range of oil 

and gas production facilities currently in operation. Accurate emission estimates are crucial to 

reasonable cost-effectiveness analyses for mitigation options. Therefore, API encourages EPA to 

focus on improving estimates of leaks emissions, including both fugitive equipment leaks and 

incidental emissions. For example, the fugitive equipment emissions can be improved by 
API Comments on Submitted to EPA

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obtaining accurate component counts at well sites, tank batteries, and compressor stations, as 

well as emission factors that apply uniquely to each of those facilities.

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. 

Refer to Sections C and E.2.

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? 

Refer to Sections C, D and E.1. No, as discussed in Section E.1 and in other places throughout 

these comments, the cost of doing various monitoring techniques varies depending on the type 

of facility along with the percent of leaking components. As discussed in Section C.1, the studies 

indicated that natural gas processing plants tend to have more leakers than compression or 

transmission of natural gas, with the lowest emissions from equipment leaks being attributed to 

well pad operations. 

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.

API is not aware of any ongoing or planned studies at this time. 

EPA should include the Picard et al., 2006 study, a companion to Clearstone II, in its review of 

leak detection techniques. That study showed that Method 21 is not efficient in detecting 

equipment leaks with high emission rates. However, a modern IR camera would be much more 

efficient in finding those leaks. 

A previous API study (Lev-On et.al., 2007) should also be considered. It entailed the 

development of “leak/no-leak” emission factors that are suitable for estimating facilities’ 

fugitive emissions when using an alternative work practice (AWP) that is based on Optical Gas 

Imaging (OGI) for detecting leaking piping system components. These are based on EPA 

recommended Monte Carlo simulations that were run on the original 1995 O&G (uncontrolled) 

field data set to establish equivalent leak/no-leak emission factors. Emission factors were 

derived for valves, pumps, and connectors/flanges for instrument leak detection thresholds 

ranging from 3 to 60 g/hr.

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 
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46

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.

Refer to Section C. As discussed in Section C.1, the studies indicated that natural gas processing 

plants tend to have more leakers than compression or transmission of natural gas, with the 

lowest emissions from equipment leaks being attributed to well pad operations. Furthermore, 

sites with above average levels of thermal cycling or vibrations, or equipment in cryogenic 

service will be more prone to leaks than others as indicated in the CAPP 2014 study. Also, 

different types of components have different leak potentials and repair lives.

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

natural gas facilities?

Refer to Sections B and D.2. No, as discussed in Section B and D.2, EPA failed to include

auditory, visual, and olfactory inspections as a leak detection method and preventive 

maintenance programs as a leak mitigation option. 

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

discuss efficacy, cost and feasibility for various applications.

Refer to Section D and E of these comments.

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?

At oil and gas production, and gas gathering and boosting facilities, the use of these 

technologies has primarily been in studies versus routine field applications. A few jurisdictions 

are beginning to require the use of some technology at upstream facilities, but typically the 

choice of technology is somewhat flexible and the promulgation of these requirements is very 

recent, so little data is available on which technologies are being used. 

Otherwise, operators may use the OGI occasionally for internal inspections for integrity 

management purposes, but not in the same manner EPA is contemplating. 

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.

No information is available on this.

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 
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47

technology is used to identify the leaking component. Please discuss efficacy, cost and 

feasibility.

This type of approach would require the purchase of two separate pieces of equipment making 

it even less cost effective. Furthermore, as discussed in Section D.1.4, using the ambient/mobile 

monitoring technologies picks up emissions upwind of the measurement vehicle, and therefore 

cannot be used to assess emissions from individual site or source types. Readings while driving 

by one location may actually be measuring another location upwind of that location; therefore, 

using it to screen sites for further OGI monitoring would be a waste of time. 

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.

Refer to Section E. The cost of detecting the leaks would typically far outweigh the cost of 

repairs. However, as discussed in Section E, not all leaks are cost effective to repair, especially in 

cases where the facility and/or production must be shut in and the equipment purged in order 

to do the repair. The cost-of-repair estimates in the studies appear to only include the 

superficial costs in a best-case scenario, as estimated by service providers and not facility 

operators. The full cost burden of repair for operators includes costs not immediately obvious 

to a third-party service provider. Any repair involving hot work (such as welding) or equipment 

replacement will generally require the production facilities to be shut in to avoid an explosion. 

Most companies do not allow hot work on equipment without it being shut in and completely 

purged. The emission reductions that would be gained by the repair would have to be weighed 

against the gas purged from the equipment. Also, the cost would need to include the lost 

production from shutting in the well or cost of lost operations from shutting in a facility such as 

the cost from lost processing at a gas plant. One could reduce the cost of repair if it were to 

coincide with scheduled of broader facility maintenance when production would be shut-down 

anyway and specialized personnel would already be on site to conduct such activities.

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?

Refer to Section E. No, it is not always cost effective to fix a leak as discussed under Question 11 

above. As shown in the Carbon Limits Study, it is not economical to both find and fix a leak. 

Furthermore, none of the studies reviewed by EPA included cost to shut-in wells, purge 

equipment, and shut-in production and processing which greatly increases the cost of a repair.

Quantification of the leak would add further cost making it even less economical. When using 

Method 21 to screen components additional resources would be needed to quantify the leak. 
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48

The concentration measured by Method 21 would need to be converted to mass emission rates 

either by use EPA’s correlation equations (convert the measured concentration to mass 

emission rates) or by direct measurements of total flow (scf/hour) via a high flow sampler or by 

component bagging. This would have to be accompanied by determination of the species profile 

of the natural gas with a gas chromatograph to enable calculation of the methane or VOC mass 

emission rates of the leak. All of these steps add considerable costs that were not reviewed in 

any of the studies.

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?

API is not aware of any new technologies being developed.

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