Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW Washington, DC 20005

- 4070 USA Telephone: 202

- 682

- 8 319 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 Strat egy 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 con trols 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, sinc e 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 provide d technical feedback and expertise throughout the de velopment of the New Source Performance Standard (NSPS) Subpart OOOO rule

. Each source addressed by the white papers w as considere d for regulation during th e 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 un changed

. A s such
, API continues to believe that no addition al regulation of oil and gas produ ction sources is

necess ary prior to the full implementation of the NSPS OOOO rule and a subsequent evaluation of
emissions

.Page 2

Considering the p otential 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 c onclusions 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:

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

res ponse to peer review and stakeholder comment (e.g., improved source description s , 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 year s, 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 lea rning 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 wel l 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, w e request the opportu nity 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/

Matt hew 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 Su bmitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

i 

## Table of C ontents

Executive Summary

................................ ................................ ................................ ............................. 1

A. Introduction

................................ ................................ ................................ ................................ .......... 3

B. Leak Definition

................................ ................................ ................................ ................................ ...... 4

B.1. Fugit ive 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 Opportunit ies at Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites (Clearstone, 2006)

................................ ................................ ................................ ...................... 37API Comments on Su bmitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

ii 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 D ocument (TSD) (U.S. EPA, 2011 and 2012)

.......... 40

F. Summary

................................ ................................ ................................ ................................ ............. 41

G. Conclusions and Recommendations

................................ ................................ ................................ ... 42

H. Charge Questions

................................ ................................ ................................ ................................ 44

References

................................ ................................ ................................ ................................ .................. 48API 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 solidi fy its understanding of the methane and volatile organic compounds (VOCs) emissions from leaks in this industry sector. The American Petroleum Institute ( API) here by 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 t ank 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 rate s 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 equipm ent 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 t he Picard , et al., 2006 study , even for fugitive equipment leaks, Method 21 is not efficient in finding leakers with high emission rate s . 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) Predominant ly 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 (bot h leaks and vents) per site was 0.23 standard cubic feet per minute (scf/min) . This is only 330 scf per day (scfd) per w ell site. At $5. 4 0 per thousand cubic feet ( Mcf ) , this is a natural gas loss of $1. 7 9 per day.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

2 Another recent study ( Carbon Limit s , 2014 ) suggests an average leak emissions rate per site of 0. 4 scf/min (leaks only , not vents ) . This is 576 scf d 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 appro ach 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

Th e American Petroleum Associati on (API) appreciates the opportunity to present th is 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” )

.

T he 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 boost er 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 inaccu rate 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 th at, based on the EIA projection 1 natural 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 poten tial 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 under used capacity and capacity that would become available due to declining production of existing producing wells

.

1 U.S. EIA, 2013bAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

4 

## B. L eak Definition

In th e White P aper, 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, o il wells that “ co

- produce ” natural gas, g athering and boosting stations, g as processing plants, and t ransmission and storage infrastructure.

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

 A gitator seals,

 C ompressors seals,

 C onnectors,

 P ump diaphragms,

 F langes,

 H atches,

 I nstruments and meters
,

 O pen

- ended lines,

 P ressure relief devices,

 P ump seals,

 V alves,

 I mproperly 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 t hroughout 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.
Additiona lly, 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 e missions 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 le a d to the belief that fugitive equipment leaks are gr eater 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 includ ing: 1) fugitive equipment leaks

, and 2) unintended incidental emissions. However, i t 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 wh il e incidental emissions often occur at thief hatches, vents

, sumps , etc. ) . While equipment leaks may typical ly continue until repaired
, incidental emissions may be
more of a temporary nature sinc e 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 rate s . 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 rate s

.
The following sections discuss in further detail f ugitive em issions from equipment leaks, incidental
emiss ions , 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,

pre ssure 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 syst em . 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 ar e 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 Paper 2

, 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 siz ed 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 , si nce 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 l east the following: the Fort Worth study (E R G, 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 oi l 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 compre s sor seals data throughout this White P aper, 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:

I ncidental 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 hatch es , or hydrocarbons drained to a water sump or tank containment. As discussed earlier
, incidental
emissions are different i n nature from the “ fugitive emissions from process equipment leak s ” that are historically covered under the LDAR programs required in NSPS and NESHAP regulations. The
differences between the two are as follows:

 I ncidental emissions are emissions resulting from exceeding equipment design and/or
deviat ing from normal operating procedures. They may occur due to lack of maintenance
, exceeding operating parameters, failure of process equipment, not following operating procedures, or o perator error; while the leak emissions covered under the traditional LDAR

progra m typically result from nor mal 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
emission s 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 emission s and impacts to operating equipment, incidental emissions are often found during routine operation checks which typically use sensory inspection methods

. Sensory inspections (name ly, 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 inspection s

. However, a traditional LDAR program is not efficient in identifying incidental emissions because monitoring survey intervals are typically quarterly or
le ss 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 rate s . However, a modern optical gasAPI 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 emiss ion 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

r educe 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 emission s , EPA should
consider cost

- effective integrated appr oaches. 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 finaliz ing 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 model l ing data and correlated monitoring a nd sampling data, the required use of Best Management Practices ( BMPs ) will result in reduced short

- term and long

term emissions from o il and gas sites ( OGSs ) . Monitoring data indicates that emissions at levels of concern pre dominately result from sites t hat 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

P reventive maintenance program s 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 emissi ons 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 a nd equipment used. An operator should be allowed to have the flexibility to design the preventive maintenance program s uch 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, 2 013API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

9 s hutdown activities 4 , e ach 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, result ing in the most cost

- ef fective redu ction 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 are a may find it more desirable to use, in addition to AVO inspections, other technology, e.g., optical gas imaging (OGI) IR camera

.
Unnecessarily b urdensome and inflexible recordkeeping and/or reporting requirements would make

any maintenance program much l ess 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 Sect ion 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 tho se four teen 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) predominant ly 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 Practi ce.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

10 facility leak emissions are due to very few highly leaking components, and (2) l eaks 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 emission s (both leaks and vents) per site (with an average of 2.3 wells) was 0.23 s c f /min ute. This is only 330 scf d per well site. At $5.40 per Mcf 5 , this is a natural gas loss of $1.7 9 per day. Another recent study (Carbon Limit s , 2014) suggests an average leak emissions rate per site of 0.4 scf/min (leaks only , no vents ). This is 576 scf d/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 e missions from leaks

, as defined by EPA in this Whit e 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.

 “ L eak” 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 uncer tainty in emission estimates for incidental emissions is substantial, e ven considering only fugitive equipment leaks, accurate emission estimates do not exist because elements such as emission factors and representative component
counts are outdated and no t 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 est imates of leaks emissions, including both fugitive equipment leaks and incidental emissions. For example

, t he fugitive equipment emissions can be improved by obtaining accurate component counts at well sites, tank batter ies , and compressor stations, as we ll 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
limi ted number of facilities

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

5 This price, $5.40 per Mcf, is the average Henry Hub natural gas spot p rice ($/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 roy alty payment, transportation cost, etc.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

11 overall leakage rates or emission factors per component. For developing representative emission
factors one has to take into account both the leak definition a nd 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 facilit y categories
in order to estimat e 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

m ethane band

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

m ay 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 plum e 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 equipme nt 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 hydrocarbon s 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 m ethane , other individual hydrocarbons and
total VOCs.

Even w it h 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 high ly leak ing components

. The studies indicate tha t 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.

F or the studies cited, which use the emissi ons data as a baseline scenario to assess the cost effectiveness of mitigation strategies, two essential features are apparent : (i) The cost s 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

Oil and Natural Gas Sector Leaks June 13 , 2014

12 API encourage s EPA to pay special attention to the uncertain ty of the derived emission estimates and the data quality issues described above. To reiterate, accurate emission estimate s are crucial to
a reasonable cost

- effectiveness analysis for mitigation options and the derivation of realistic marginal abatement co sts

.

Fu r ther 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 w ere 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) a verage e mission f actor

a pproach ; (b) s creening r anges a pproach ; (c) EPA c orrelation a pproach ; and (d) u nit s pecific

c orrelation a pproach

.

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 t he 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 data 6 and updat e 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 M ethod 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 equation s for determining mass emissions. One of the features of the study was that t he facilities were divided into categories of eastern and wester n 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 2007API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

13 year overall methane emissions from all the natural gas sector in the U.S. amounted to 314 + 104 ( + 33%) bill ion 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 1 6.23 ( + 45% ) Bscf , and the
contribution from gas well emissions wa s 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) The re is a need to look at regional differences in natura l gas composition because the demarcation of Eastern and Western natural gas does not seem to be relevant any longer. (3) T he global assumption that average emission rates should be adjusted to m ethane 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 s ites (1

- 17) for each region which is hardly representative

. To improve component counts, f ar 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 factor s 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
obtain ed 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 m ethane 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 Techn ical 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 decadesAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

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,
201 4 )

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 product ion 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. The se regions are: North East, Midcon tinent, Rocky Mountain, South West, West Coast, and Gulf Coast. Distinct e mission factors are used for estimating emissions

– for each of the regions

- from gas wells, separation equipment, gathering compressors, gathering pipelines, drilling and well comp letions, 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 adjust ments that reflect more recent data on regional gas compositions ( 2001 GTI study ). For natural g as processing and gas transmission, emission factors are not broken into regions, and national level emission estimates are provided. Potential m ethane leak emissions from gas wells and field separation equipmen t 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 o f 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 S ystems in the national inventory

. (2) Moreover, API has al so 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 (addre ssing 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 suggest ed including “associated gas emi ssions” 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 the se emissions are potential emissions factors represent ing whatAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

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 reiterate d 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 support ed EPA’s action to continue to d isaggregat e emission source information and applicable emission reductions, to provide better transparency of “net” GHG emissions for each source type.
The approach historicall y 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 perf ormed 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, v alves
, 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 natur al gas value of $5.40 per Mcf, this is

Table C

- 1: Emissions Per Well (a ll 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 + 0.024API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

16 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 i n 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 f ocus of the study was not on e quipment l eaks and these measurements were performed in
an ad hoc fashion with no a prior i design for representativeness of data collected and results

. (3) The methodology used in the study does careful ly account for m ethane emissions by characterization of gas composition at every site and subtraction of non

- m ethane 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, drilli ng operation, fracking operation, and completion operation (flowback).

The sampling strategy was to survey sites by IR c amera to identify all larger leaks which were measured with HiFlow samplers

. Concurrently, a survey of 10% of all components was conduc ted 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 t he 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 emi ssions 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 p neumatic valve controllers and t he highest emission rates were d etected with
the IR c amera 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

Oil and Natural Gas Sector Leaks June 13 , 2014

17 ( 6 ) At 96 of the 375 sites tested no emissions were detected by the IR c amera ; most of these sites
contained three wells or less.

EPA White Paper 2.7

- Measurem ents 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 emi ssion 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 speci ation 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 auxili ary 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 fr om 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 emi ssions 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 publishe d a final report in April 2014.
There are no significant difference s 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 leak s , 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, c ompressor 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 a t 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 l eaks from static components,API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

18 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 batter ies also contributed by leaks.

The report references the ICF work to state that 30% of m ethane emissions from onshore natural gas production emissions are from l eaks but this lump s together traditional equipment leaks and

vents. Carbon Limits claim s that
, based on their database
, 35% were due to leaks , but they too are lumping together both venting and leaking includin g 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 c ommon.

Table C

- 2: Comparison of the Carbon Limits S tudy with P reviously P ublished W ork (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, t ank 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 R esults

(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 leak 7 12 NA 7 NA

Average vent 8 NA NA
Average emissions 9 0.8 12.2
University of
Texas 2013 Average emissions 146 0.23 10 NA NAAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

19 leaks for the purpose of this White Paper. From the comparison tabl e above, the average leak rate (excluding vents) at wellsites and well batteries was found in this study to be 0.4 scf/m inute

. 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 lo ss, 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 pressur es 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/sta tion 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 th e 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.
Selec tion 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 v a ry between subcategories.”
All of these factors will significantly i mpact 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 condu cted 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 em issions and some estimated emissions. The ratio of measured vs.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

20 estimated emissions was not quantified, so it is highly uncertain whether the economic conclusion can be justified

. (8) The authors make a sweeping a ssum ption that over 90% of the emissions are f rom 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 rep air. The authors do contradict themselves when they acknowledge that the net present value ( NPV ) of a n 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 i mportant 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
cla im 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

- ef fective 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 ( CO 2e )
emissions is set at 25 for m ethane . Although this is identical to EPA’s revised GWP for reporting
from 2013 and beyond , it is not comparable with available data . T he 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 m ethane. 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 As sessment 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 p art 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

m ethane , along with the different GWP that is cited for deriving CO 2e emissions

. (12) The authors state that the VOC and CO 2 e 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 C O 2e and a VOC emission factor have been calculated (see Appendix 3).” They did not use actual measured composi tions 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 CH 4 concentrations”. The report presents aggregated emission results by state, which are ref lected in the White Paper.

API’s CommentsAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

21 (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 appro ach 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 U niversity of T exas, Austin
, m easurements 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 a s 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 fr om pipeline leaks from transmission of natural gas , for a sum total 343,400 metric tonnes
of m ethane. ( 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 m ethane 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 p rovided in briefings in which they have indicated that for the period 2011 to 2018 net m ethane emissions from natural gas systems is expected to decrease by 1% while net m ethane 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 CO 2 emissions and not CH 4 emissions

. (6) ICF does not provide any discussion of the impact of production decline and the plug and
abandon ment of wells with lower production of wells.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

22 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 v oluntary Dir ect ed 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
f acilities 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 therefo re 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 ) Abou t 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

app roximately 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 studie d.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

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

prog ram. ( 2 ) Fugitive e quipment 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 quant ified m ethane 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 St udy

(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 geogr aphic brea d th, variety of facilities, differences in the characteristics of products handle d , and operating practices of the companies. Conclusions from this study should only be applied to gas processing plants. (6) Clearstone (2006) references a separat e 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. TheAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

24 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/da y 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
shoul d 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 als o 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 equipm ent 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 surve yed 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 CO2 e per year. The 320 economically repairable leaking components
resulted in an estimated 470
, 8 00 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 point s 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 leak ing 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.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

25 (3) In contrast to the percentages of emiss ions accountable to each component reported in Clearstone II, (see ( 2 ) under EPA White Paper 2.12 above ) , th is 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 larg est leaking points resulted in 226
, 3 00 m 3 /y or 48% of the total leak emissions . The
five leaks that were not detected by Method 21 emitted only 62
, 3 00 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 maj or 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 contributio ns 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 em issions are detectable by a leak imaging
infrared camera.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

26 Table 10 from the final report present s 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 sur vey 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 surv ey 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 we re 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 Fugit ive 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, de tailed 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 in ventory 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 wit hout 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 em issions 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 compone nt 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 sub

sections: 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/docume nts that had information about cost

- effectiveness analysis or payback period estimates for repairi ng 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.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

27 

### 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 audi tory , visual, olfactory (AVO) monitoring or proper maintenance and repair pr ograms. EPA s eems 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 t hat 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 inclu de techniques not only for detecting leaks, but also for helping prevent leaks. The complete omission of these two ideas from the White P aper is extremely concerning. EPA should evaluat e the AVO method for detectin g 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 t he 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 instrume nt. 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 claim s 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
ins trument 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 chro matograph, but these devices are expensive, impractical to use in the field, and not required to comply with Method 21)

.

More cost data is need ed 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

Oil and Natural Gas Sector Leaks June 13 , 2014

28 Operating costs, such as calibrations, maintenance, and operator training and certifications have not been rigorously quantified and incorporated into the c ost

- effective ness 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. S ome 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 fo r 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 refiner ies. 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 com ponents 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 o f the ten largest emission points shown
in Table 5 of the paper

, only five of them we re detected by traditional (M ethod 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 mai ntenance, and training are needed directly from operators or turn

- key vendors. Some typical costs include:API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

29  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://c ourses.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, a coustic 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)

con cluded 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 form ation of a well

- developed atmospheric plume, detectable at ground level, downwind of the site. Only a fraction of s ites are amenable to this type of sampling , d epend ing 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 speci fic 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, EP A 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 th e mobile leak detection technique.” However, such a n 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 pinp oint specifically where the methane is coming from because it depends on meteorological and geographical conditions at the time and location of the measurement.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

30  The mobile leak detection techniques capture a specific point in time. Some GHG emission sou rces result from episodic events that could be detected from the mobile monitoring but would not be detected in a n 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 O GI 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 P aper 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 bel ow 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 Detecti on
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 qua ntify 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 t hat 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 woul d 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. tha t 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.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

31 In considering any le ak 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 addit ional 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 othe r studies. There was no validation of the data presented in the se 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 inspectio n 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

T he 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 a nd 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

m ust include all the following cost s in performing an ana lysis of the cost effectiveness: planning and setup; leak detection; repair; recordkeeping and potentially reporting; and cost s incurred due to the remote, dispersed, and unmanned nature of facilities . In addition, a cost effectivene ss 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 compressi on 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:API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

32 o Developing a n 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 compone nts at each facility,

o Number ing 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 Se lecting 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 dete ction

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 t hat 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 choose s to do in

- h ouse 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 c over 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 i nclude 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.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

33  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 eq uipment after the repair to confirm that it was repaired. Also, EPA must consider the cost of time for operators or leak survey contractor s 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
havi ng 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 . Mos t 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 agai nst 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 reco rdkeeping 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 tr acks 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 re ports 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 re

readings will be extremely onerous and difficult. T he cost of such a monumental effort would be extremely high

.

 Remote, dispers ed and un

- manned nature of the industryAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

34 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 (un

manned). Operators, maintenance crews , and monitoring teams often have to travel significant distance s 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 location s that can be monitored each day. Historical LDAR programs
have be en 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, an d well production facilities.

Cost

- effectiveness analys e s 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. S pecifically, 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

- $1 4 0/hr)

o LDAR Project Manager

– ($100

- $1 9 0/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 (C arbon Limits, 2013
, and UT
, 2013 )

Actual cost data from implementation o f emerging state programs, such as, Colorado’s Regulation 7
and Ohio’s Oil a nd 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 pr esented a summary of five studies/documents to demonstrate various appr oaches to deciding whethe r to repair the leaks found during the survey s or not, provided repair is not mandatory. Examples of the approaches include d the net present
value (NPV) analysis
, and the payback period analysis. EPA did not offer a critical review orAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

35 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 comme nts related to the emissions
issues in those studies in Section C , which will not be repeated here. T he most significant and salient points with regard to leak repair cost and effectiveness are dis c ussed below. API’s comments
on EPA’s inclusion of the Na tural 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) E missions identifi e d 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 th e purpose of this White Paper. (2) T he 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 f or 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...
wi ll 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
, “ ... w hen 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 indiv idual well sites and well batteries are aggregated into a group, the aggregated NP V 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 , allowingAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

36 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) W ith 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, t he 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 burde n shouldered by the operator . The cost to remove the valve for repair is greater than if the valve can be repaired in place. T he study does not consider the cost for shutting down the facility, purging the equipment, and loss of production or processing a s 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 an d 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 so me 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 “ Incre asing 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 overl y optimistic and underestimate the real costs. The assumptions of the cost
components probably are n o t 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 Redu ce 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 rep air 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 wouldAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

37 cer tainly 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 g as 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
emission s are also included , such as flaring, combustion equipment, storage tanks, etc. (4) The payback periods analysis approach do es 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, a nd 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 cost s

. (7) These comments are also applicable to the Clears tone 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 ( C learstone, 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 f acilities 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

Oil and Natural Gas Sector Leaks June 13 , 2014

38 (4) The a ssumed gas price in th is study was $7.1 5 per Mcf , which is more than 32 % hi gher
than $5. 4 0, the average Henry Hub natural gas spot price from January 2001 to April
2014

. (5) The c ost s of leak detection survey s w ere not included in the cost consideration , nor were many other costs discussed in Secti on 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 D irected I nspection and
M aintenance (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 component s (U.S. EPA 2003a, U.S. EPA 2003b, U.S. EPA 2003c).” However, on closer examination of the referenced
documents , API believes th is 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 gat e station s;

 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 p rocessing) 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 th at... 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 cost

effective gas savings will vary widely depending upon such factors as th e 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

Oil and Natural Gas Sector Leaks June 13 , 2014

39 EPA states in the section 3.2.4 of the White Paper that “from p revious 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 negat ive NPV.

Moreover, b ecause 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

. O nly the projects
with the most significant emissions reductions are selected and i t is not realistic to expect every operator would be in a position to achieve the same results, given differences in location, resources, fac ility 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 M ethane emission factor, while in the EPA White Pape r 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 imple mentation 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 p rograms, 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 program s

. 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.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

40 E.2.6. NSPS Subpart OOOO Technical Su pport Document (TSD) ( U.S. EPA , 201 1 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 cos t 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 f r om 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 th e 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 aspect s of the analysis in this document, it still showed that it is not

cost

- effective to require NSPS LDAR program s (e.g., Subpart s V V 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) :API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

41 Table E

- 2: Summary of VOC Cost Effectiveness of the LD AR Options

(from the 201 2 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 industr y 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. Summar y

I n 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 t he 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 represent ative 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 th e 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 rat e per site.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

42  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
VV a , is not cost

- effective for oil and gas production sites.

 EPA stated that “ambient/mob ile 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 a n 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 fo r 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 de tection

cost and all o the r cost s discussed in Section E1 are included. As discussed earlier in this document, some of studies cited by EPA showed very low equipment leak emission s, resulting in only $1.7 9 /day/site ( UT , 2013), or $3.11/day/site (Carbon Limi ts, 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 economi cal.



## G. C onclusions 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 a re 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 emi ssions 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

Oil and Natural Gas Sector Leaks June 13 , 2014

43  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 nati onal 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 fact ors 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
opt ions. As the first step, EPA should focus on improving estimates of leaks emissions, including both fugitive equipment leaks and incidental emissions. For example , t he fugitive equipment emissions can be improved by obtaining accurate component counts at well sites, tank batter ies
, 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 recen t studies cited by EPA included vented emissions. Examples
include the Greel e y, 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 repairi ng 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
inst ance, 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 w ere 0.23 standard cubic feet per
minu te. This is only 330 scf d per well site. At $5.40 per thousand cubic feet (Mcf), this is a natural gas loss of $1.7 9 per day. Another recent study (Carbon Limit s , 2014) suggestsAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

44 an average leak emissions rate per site of 0.4 scf/min (leaks only, not ve nts) . 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 in spections 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 t ypes 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 low

cost 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 p reventive 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 th e 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?

R efer to Section s 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, e missions from leaks as defined by EPA in this White Paper (including both traditional fugiti ve 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 em ission 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 , accur ate 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 estima tes 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 , t he fugitiv e equipment emissions can be improved byAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

4 5 obtaining accurate component counts at well sites, tank batter ies , and compressor stations, as well as emission factors that apply uniquely to each of those facilities.

2. Please comment on the approaches for quantifyi ng 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 Section s 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, t he 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 techn iques

. That study showed that Method 21 is not efficient in detecting equipment leaks with high emission rate s . 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 consid ered. 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 syste m components. These are based on E PA 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 conne ctors/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 facto rs that could affect the potential for leaks are the number and types of equipment, the maintenanceAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

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 belie ve to be important.

Refer to Section C . As discussed in Section C. 1, t he 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 averag e levels of thermal cycling or vibratio ns, or equipment in cryogenic
service will be more prone to leak s 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
audi tory , 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 sta tion) affect which leak detection technology is used?

A t oil and gas production, and gas gathering and boosting facilitie s, the use of these technologies has primarily been in studies vers u s routine field application s. 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 i s 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 progra ms 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 OGIAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

47 tech nology 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, u sing 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 meas uring 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

ove rall 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 productio n 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 b roader 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 economic al

. When using Method 21 to screen components additional resources would be needed to quantify the leak

.API Comments on Submitted to EPA

Oil and Natural Gas Sector Leaks June 13 , 2014

48 T he concentration measured by Method 21 would need to be converted to ma ss 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 chromatogra ph to enable calculation of the methane or VOC mass emission rates of the leak. All of these steps add considerable cost s that were not reviewed in any of the studies.

13. Please co mment 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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