Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW

Washington, DC 

20005-4070 USA

Telephone: 202-682-8319

Fax: 202-682-8031

Email: ToddM@api.org

www.api.org

June 13, 2014

Mr. Chris Frantz

US EPA 

109 T.W. Alexander Drive

Mail Code: #143-05

Research Triangle Park, NC 27709

Re: EPA VOC/Methane White Paper on Hydraulically Fractured Oil Well Completions and 

Associated Gas During Ongoing Production

Dear Mr. Frantz:

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

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

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

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

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

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

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

methane controls should be required at this time. 

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

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

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

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

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

government or states.

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

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

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

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

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

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

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

emissions.
Page 2

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

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

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

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

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

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

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

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

improved understanding of emission quantification, misconceptions about emission mitigation 

options)

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

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

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

emissions and await the pending study reports

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

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

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

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

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

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

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

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

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

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

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

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

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

Sincerely,

/s/

Matthew Todd

Cc: Peter Tsirigotis, EPA

David Cozzie, EPA

Bruce Moore, EPA
Comments on

Oil and Natural Gas Sector Hydraulically Fractured Oil 

Well Completions and Associated Gas During Ongoing 

Production

by EPA Office of Air Quality Planning and Standards

June 2014

Prepared by

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

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

and Associated Gas During Ongoing Production June 13, 2014

i

Table of Contents

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

A. Specific Comments................................................................................................................................4

B. Emissions Data and Estimates...............................................................................................................7

C. Emission Mitigation Techniques.........................................................................................................14

D. Summary .............................................................................................................................................16
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

and Associated Gas During Ongoing Production June 13, 2014

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Executive Summary

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

Gas Sector Hydraulically Featured Oil Well Completions and Associated Gas During Ongoing Production”

(referred to as “the White Paper”) to, as stated in the Preface, seek input and solidify its understanding 

of the methane and volatile organic compounds (VOCs) emissions from these sources in this industry 

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

document. These comments are organized to provide general comments that are applicable to the 

white paper followed by comments that address specific topics within the white paper.

EPA’s stated intent for this white paper is to “fully evaluate the range of options for cost effectively 

cutting VOC and methane waste and emissions” (Preface). The stated purpose for this white paper is 

“to summarize the EPA’s understanding of VOC and methane emissions from hydraulically fractured oil 

well completions and associated gas during production” as well as to present “EPA’s understanding of 

the mitigation techniques available to reduce these emissions” (Introduction). 

API’s assessment of this white paper is that it fails to reasonably or accurately characterize industry 

operations associated with hydraulically fractured oil wells both when production is initiated in new 

wells immediately after conclusion of hydraulic fracturing operations and during long term operations, 

particularly when not all gas produced can be sent to sales due to limitations on gas gathering 

infrastructure (known in industry as “stranded gas”). EPA makes inaccurate and unsupported 

assumptions regarding industry practices, for example, assuming that all gas produced during the 

“flowback” phase is vented rather than flared or sold and that all stranded gas is vented rather than 

flared. These inaccurate assumptions lead to highly overstated estimates of methane and VOC 

emissions, which leads to overstating the economic and environmental benefits of potential new 

regulations to require emission controls or mitigation. 

The key point the EPA has not recognized is that during the flowback phase, in a majority of cases, 

industry practice is to vent gas only as long as is necessary for the well to develop flow at sufficient 

pressure such that the production stream can be routed to a test or production separator. Once routed 

through the separator, recovered gas is most often routed to a flare and combusted or to a sales or in 

field utility line, if available. This typically occurs within the first day of the flowback period yet EPA has 

assumed this gas is vented throughout the entire flowback period (3 or 7 days is used in the white 

paper, depending on the cited reference). The operator’s driver for minimizing venting is safety and it is 

often followed even when emission controls are not required. Venting, while used in some cases, is 

done only where safety and health exposure risks can be managed at levels that are acceptable to the 

operator. 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

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EPA does not make any effort to determine or discuss what level of control is currently in use by 

industry or to accurately estimate actual VOC and methane emission volumes. Assuming that all gas 

produced during the flowback phase and that all stranded gas is vented and not combusted leads to 

gross over estimates of VOC and methane emissions, which in turn leads to overestimation and 

incorrect conclusions regarding the economic value of any mitigation practices or technologies. EPA 

should base its emission estimates on current levels of control in use. EPA should review 2011 and 2012 

Greenhouse Gas Reporting Program (GHGRP) data to determine an estimate of the percentage of oil 

wells that presently use flaring or REC to control emissions from HF completion flowback. As API shows 

in these comments, the GHGRP, which has been rejected out of hand by EPA, is a potentially important 

data source.

In summary, it is API’s position that this white paper does not present an accurate description of current 

industry operations and practices with respect to controlling emissions from hydraulically fractured oil 

wells nor does the white paper provide a full or representative evaluation of options for cost effectively 

reducing VOC and methane waste and emissions. None of the emission studies cited by the EPA in the 

white paper were designed to characterize current industry operations or quantify controlled and 

uncontrolled VOC and methane emissions from hydraulically fractured oil wells. As a result, in using 

most of the studies cited, EPA has made incorrect assumptions and over stated emissions estimates in 

an effort to create data from those studies where, in most cases, it is not available. Because of this 

situation, the API strongly recommends a study that builds on the data available in the GHGRP be 

conducted to gather representative data from multiple producing regions to accurately characterize the 

actual range of industry practices to more accurately estimate VOC and methane emission volumes.

Terminology

In many instances, terminology common to the oil and gas industry that is used in this white paper is 

being used incorrectly. For industry, it is critical that the terminology be used correctly and consistent 

with long standing industry and state agency use. This will ensure that intent and concepts are 

understood both by the EPA and the members of the regulated community going forward. Misuse of 

terminology will lead to confusion and misunderstanding. Specific examples are provided in the detailed 

discussion below.

Industry Operations and Practices

As noted above, the EPA has not provided an accurate description of current industry practices and 

operations in this white paper. If not corrected, the inaccurate descriptions of industry operations and 

practices are very likely to be taken by the public as being accurate, when in fact they are not. This leads 

to further confusion and increased levels of concern that are not warranted. The fundamental flaw in 

this white paper is the EPA’s assumption, made largely in the absence of actual data, that all gas 

produced during the flowback phase and all stranded gas is vented directly to the atmosphere rather 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

and Associated Gas During Ongoing Production June 13, 2014

4

than being flared. It is incumbent on EPA to use the best available data to accurately characterize 

industry operations and practices and where those data are not immediately available, to take steps to 

gather additional representative data. As API shows below, additional data is immediately available 

from EPA sources and API plans to conduct a brief survey of operators to better define current 

operational practices when initiating production and will gather and provide those data shortly.

Following the public announcement that a white paper was being drafted on emissions associated with 

oil well completions, API submitted early feedback (March 2014) to EPA and those comments are 

attached for further consideration.

A. Specific Comments

Terminology

 EPA introduces the term ”coproducing well” to describe wells that produce both oil and gas and 

appears to be using the term to better identify how associated gas is handled. API questions the 

value of introducing a new term that is not in common use by industry. A majority of wells that 

produce oil also produce gas, although the volume of gas produced can vary widely between 

wells or during the life of an individual well. API recommends EPA follow state approaches to 

defining oil and gas wells without introducing a new term that could lead to further confusion.

 In the first paragraph of the Introduction, EPA makes the statement that the “use of horizontal 

drilling combined with hydraulic fracturing” will be referred to as “simply hydraulic fracturing”. 

This is an incorrect use of the terminology that must be corrected. Hydraulic fracturing is a very 

discrete step in the overall process of the development of unconventional oil and gas resources. 

Typically, the hydraulic fracturing of a shale well is a formation stimulation technique that is 

conducted during the completion phase of installing a new well. A multi-stage hydraulic 

fracturing operation usually takes 3 to 6 days. The correct terminology for this statement in this 

context would be to refer to horizontal drilling and hydraulic fracturing as “unconventional 

resource development” or “drilling and completion”. This is consistent with industry’s current 

and historical terminology.

 In the fourth paragraph of the Introduction and the first paragraph of Definition of the Source, 

EPA’s description of completion and recompletion operations is inaccurate and therefore 

incorrectly used throughout this paper. Completion operations on a new well start when the 

operator makes the decision to install all of the equipment and perform all operations necessary 

to produce hydrocarbons from the well. These operations include running and cementing 

production casing, performing formation stimulation operations such as hydraulic fracturing, 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

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installing production equipment like the packer and tubing in the well, installing the wellhead 

and “christmas tree” equipment and installing surface production handling equipment like 

flowlines, separators, tanks, and pumps. Recompletion typically refers to the situation where an 

operator performs the operations necessary to change the producing interval of the well from 

one producing zone to another (normally a shallower formation). The term rework is used when 

an operator performs work (adding perforations, formation stimulation, or other 

repair/remedial activity) on a well without changing the producing formation of the well.

 EPA’s proposed definition of well completion (Section 2.1) is inaccurate. As noted above a more 

accurate definition is 

“the process of installing equipment and performing operations necessary to produce 

hydrocarbons from a well including running and cementing production casing, performing 

formation stimulation operations such as hydraulic fracturing, installing production 

equipment such as casing and tubing in the well, installing the wellhead and christmas tree 

equipment and installing surface production handling equipment such as flowlines, 

separators, tanks, and pumps”. 

EPA’s inclusion of the phrase “which may vent produced hydrocarbons to the atmosphere via an 

open pit or tank” is not accurate, nor is it relevant to the definition. The proposed definition 

should not reference venting, flaring or other mitigations or controls that are commonly used. 

Venting is also not intrinsic to completion operations, so for both of these reasons the 

statement should be removed.

 EPA’s definition of hydraulic fracturing in Definition of the Source requires modification and 

should read as follows:

“A formation stimulation operation in which a hydraulic fracturing fluid is pumped down 

a well into a target formation under pressure high enough to exceed the formation 

fracture gradient to create micro-fractures and place proppant through which oil or gas 

can flow into the well bore.”

API notes that the hydraulic fracturing fluid is composed of a working fluid (e.g., water, CO2 or 

propane) and additives that is used to create micro-fractures, transport proppant into the 

micro-fractures and prepare the formation for production. 

Similar to the comments above, the phrase “that subsequently require high rate, extended 

flowback to expel fracture fluids and solids during completions” in the EPA’s draft definition is 

not intrinsic to hydraulic fracturing and should be removed. Fluid recovery flow rates and 

volumes are highly variable between producing regions. While fluid recover certainly does 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

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occur, it is not considered a primary part of the hydraulic fracturing operation, it is considered 

part of the process of initiating production (commonly called “unloading”) that is common to all 

wells, both conventional and unconventional.

 The EPA incorrectly describes hydraulic fracturing fluid (Section 2.1) as a “water emulsion” 

which suggests the presence of oil to create an emulsion. Most hydraulic fracturing fluids are 

viscosified fluids using polymers (natural or synthetic) to create the fluid viscosity necessary to 

carry the proppant into the fractured formation. Fluids viscosified with polymers are not 

emulsions.

 The EPA incorrectly uses the term backflow. Use of this term is not necessary and by its use 

creates a degree of confusion. As the cited definition states, backflow conditions are created 

when pressures between different formations in the well cause fluid to flow between these 

formations. This type of flow is not relevant in hydraulic fracturing operations and does not 

accurately describe the condition addressed by the EPA. The condition described in the text 

(Section 2.1) by the EPA is recovery of the injected hydraulic fracturing fluid and is called 

“flowback” or unloading.

 In multiple instances in Section 2.1, the EPA refers to “backflow (or flowback) velocity”. The 

correct term in this case is “flowback rate” (volume per unit time).

 The EPA’s description and definition of associated gas is incorrect. The simple definition of 

associated gas cited by the EPA provided by the North Dakota Industrial Commission is much 

more direct and consistent with long standing industry usage. The EPA incorrectly ties the 

disposition of the gas to the definition by stating associated gas is either vented or flared. 

Associated gas is typically sold and often used as field gas to power operating field facilities or 

used on other ways. The disposition of the gas is not relevant to its definition. A clearer 

definition of associated gas is:

“any gas (at standard conditions) produced from an oil well (as defined by the 

jurisdictional agency)”.

A serious consequence of incorrectly defining “associated gas” is that EPA misrepresents the 

data in Appendix A which reports on “associated gas” from hydraulically fractured oil wells in 

2011. Because the white paper wrongly defines associated gas as stranded gas that is vented or 

flared, the reader is led to the conclusion that all hydraulically fractured oil wells listed in 

Appendix A drilled in 2011 resulted in stranded gas that is either flared or vented. This is 

categorically wrong, there are numerous areas where associated gas is sold and not stranded. 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

and Associated Gas During Ongoing Production June 13, 2014

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Additionally, the DI database used to compile the data does not identify the disposition of 

produced gas, which makes drawing the conclusion made by the EPA impossible.

 The EPA’s definition of “associated gas emissions” appears to be bounded by operational 

conditions (access to infrastructure) that are not applicable to a correct definition. Industry 

defines gas that cannot be sold due to limitations on infrastructure as “stranded gas”, without 

making any assumptions regarding its disposition, other than it cannot be sold. As noted above, 

throughout this white paper, the EPA’s default presumption is that all stranded gas is vented, 

which is incorrect.

 The API recommends that the EPA define uncontrolled methane or VOC emissions as follows:

“the direct release to the atmosphere without combustion or other form of destruction”

B. Emissions Data and Estimates

As the EPA correctly notes in reference to their cited studies, “most of the available data were not 

collected specifically for the purpose of estimating emissions”. Because of this, the EPA has made 

estimates and assumptions in an attempt to use these studies to describe and quantify methane and 

VOC emissions during oil well completion and production operations. As noted above in the general 

comments, the API is particularly concerned with the EPA’s default assumption that all gas produced 

during the completion phase and that all stranded gas that is produced is vented, not flared, used in the 

field or sold. Use of gas in the field by operators in support of production operations is largely ignored in 

this white paper. Operators commonly use associated gas as fuel for small engines, for oil treatment 

(heater treaters), gas dehydration, and for gas lift (artificial lift). In conventional operations, associated 

gas can also be used for reservoir pressure maintenance. The API will show later in these comments 

that their assumption regarding associated gas is incorrect.

The EPA also notes that there is variation in how oil wells are defined. This variation is the result of the 

oil and gas industry being primarily regulated by multiple state agencies and each state holding the 

ability to define oil and gas wells based on their specific needs and situations. The API recommends that 

to the extent practical, the EPA follow those state specific definitions so that their data and descriptions 

remain consistent with each state’s records.

Section 3.2 - Fort Berthold Federal Implementation Plan (FBFIP)

 The EPA notes that the FBFIP “requires a 90-98% reduction of VOC emissions from gas not sent 

to a sales line using pit flares, utility flares and enclosed combustors, all technologies that were 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

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found to be industry standard practice (emphasis added) in the Fort Berthold Indian 

Reservation. Despite the fact that the required emission controls were found to be standard 

practice, the EPA appears to have assumed no controls were used when estimating emissions 

from these sources in this report. The EPA does not characterize these emission levels as 

“potential emissions”; instead, they are simply and incorrectly offered as “estimated emissions”.

 The EPA expresses concern (“certain qualifying limitations) in the white paper over the 

variability in production characteristics, rates and volumes. Unlike conventional oil and gas 

producing formations, unconventional oil and gas producing formations have a much larger 

areal extent. Because of this, significant variability in product characteristics, rates and volumes 

is common and should be recognized and considered when trying to develop a representative 

selection of wells and production operating practices. The variability of data between different 

fields or different formations is common and should not preclude use of data from any 

particular area. This variability does however point to the value of gathering data that is 

representative of the industry’s operations nationally when crafting a rule with national 

applicability. This last point is discussed further in these comments.

 The data in Table 3-2 includes estimates for average gas volume over the 7-day flowback period 

and for average uncontrolled VOC emissions which do not appear to consider the fact that, as 

stated above, emission control rates are between 90 and 98%. The actual emission levels are 

clearly much lower when the required control rates are applied and EPA should use the 

controlled rates in this white paper to maintain an accurate and representative discussion going 

forward.

 Footnote “d” in Table 3-2 notes that the data submitted by XTO Energy were rejected because 

the reported oil production and associated gas production had the same value, although API 

notes, different units. API has confirmed with XTO Energy that these values are in fact correct as 

reported and should be used. The parameters having the same value with different units is 

simply a coincidence and inherent to the variability of the data as described above.

Section 3.3 – ERG, Inc. and EC/R Analyses of HDPI Data

 This evaluation has assumed that all gas and VOC production is uncontrolled. No effort has 

been made to determine what the actual rate of control/ emission reduction was in use during 

that time period. API data offered below shows that a majority of wells/completions were in 

fact employing emission reduction controls. At a minimum, these data should be revised to 

reflect the estimated level of controls derived from the data submitted by the API in order to 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

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present a more accurate picture of the remaining emission reduction potential and therefore 

accurately evaluate the economics of those controls. If EPA cannot determine the estimated 

level of controls in use, these emissions should be identified only as “maximum potential 

emissions”.

 In Appendix A, use of a Gas to Oil Ratio (GOR) of 12,500 is described as being consistent with the 

methodology used in the 2012 Oil and Natural Gas Sector NSPS development, which is incorrect. 

The NSPS does not recommend or specify any GOR for differentiating oil and gas wells. There is 

currently no single accepted value of GOR for this purpose. The values used by state regulatory 

agencies vary widely based on their historical needs and practices. API recommends that in any 

work trying to describe oil vs. gas wells that they do this on a state by state basis, using the value 

in use by the specific state. This will maintain consistency between the individual state data and 

the data used by EPA. 

 The nationwide uncontrolled emission values estimated by ERG and EC/R cannot be replicated 

using the data provided (page 13 of white paper). For example, the white paper states “VOC 

emissions are 116,230 tons per year (i.e., VOC emissions /completion of 20.2 tons/event times 

the total oil well completion event per year of 5274). 

o 20.2 x 5274 = 106,534.8 tons, not the 116,230 tons stated in the white paper.

o These same errors carry throughout the emission estimates in this section.

Section 3.4 - Environmental Defense Fund and Stratus Consulting Analysis of Oil Well Completions

 The data that serves as the basis for this study is taken directly from several of the other 

references used in the EPA’s White Paper and as such, should not be considered purely original 

work. It presents the same data generated by others with similar conclusions.

 All gas and VOCs produced during the flowback phase appear to be considered uncontrolled 

emissions without qualification as identified in Table 3-5.

Section 3.5 – UT Study

 As with the EDF study, API cannot replicate the EPA’s methane emission calculations (page 13) in 

the white paper.

 API agrees that it is worth noting that with well GC-3 in this study using a REC achieved a 98.8% 

methane emission reduction. API further notes that wells GC-1, GC-2 and GC-7 did not utilize a 

REC and achieved a 97.9% average methane emission reduction. Based on this very small 

example, using a REC provided an incremental methane emission reduction of 0.9% when 
API Comments on Submitted to EPA

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compared to a flare. The API recommends that the incremental reduction of 0.9% be used 

when evaluating the economic value of utilizing a REC rather than the total emission reduction.

Section 3.6 – Methane Leaks from North American Natural Gas Systems

 All methane produced during the flowback phase appears to incorrectly be considered an 

uncontrolled emission as identified in Table 3-7.

 EPA notes that this study used the O’Sullivan method for estimating completion emissions while 

the other studies used a different method. Neither of these methods provide estimates of 

completion emissions, they arguably estimate gas production during the flowback phase. The 

EPA has incorrectly assumed that all of the gas produced during this period is emitted. Neither 

the study authors nor the EPA provide any actual production data that validates the use of 

either of these estimation methods either for early production volumes or emission volumes. 

Although this study only examines shale gas well completions, EPA should have noted other 

important points from the 2012 O’Sullivan, et. al., paper, which makes several important points:

(1) The O’Sullivan paper references estimated emissions from completion flowback as “potential

fugitive methane emissions”, which is a much more accurate than just “uncontrolled emissions”. 

(2) The O’Sullivan paper acknowledged present widespread industry use of both flaring and 

reduced emissions completions due to both economic benefit and existing state regulations. For 

example, from page 4, “However, our main estimate of actual fugitive emissions is based on a 

‘current field practice’ gas handling scenario, where 70% of potential fugitives are captured, 15% 

vented, and 15% flared. This we believe is a reasonable representation of current gas handling 

practices in the major shale plays.” 

(3) The authors estimated that current use of available control technologies gives estimated 

actual emissions that are 75% less than the estimated potential emissions. 

Section 4.0 – Emissions Data and Emission Estimates – Associated Gas From Hydraulic Fractured Oil 

Wells

 The EPA states that the Gas:Oil Ratio (GOR) could be used to develop an emission factor that 

could be used to estimate uncontrolled gas emissions. This statement is absolutely incorrect 

and is a fundamental flaw with this white paper. The GOR can be used to estimate gas 

production if oil production is known, but it says nothing about the level of emission control 

applied by the operator. The use of emission controls is completely independent from GOR. 

One has nothing to do with the other.
API Comments on Submitted to EPA

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Section 4.1 – Greenhouse Gas Reporting Program (GHGRP)

The EPA appears to have largely ignored the GHGRP as a potential source of information relevant to this 

effort. The API has conducted a more thorough review and found there is substantial information that 

informs this discussion. A total of 77 operators have voluntarily reported data from 1,004 completion 

events in 2011 and 2012 in oil producing formations to the GHGRP.

API Review of the GHGRP

API reviewed data in the GHGRP for potential information relevant to this effort and found a number of 

submittals that should be considered. While operators are not required to report oil completions under 

the GHGRP, it appears many wells are being voluntarily reported. By selecting wells that were identified 

as being completed in known oil producing formations, API identified 1,004 completion events that can 

reasonably be assumed to be hydraulically fractured oil well completions. While this is a relatively small 

fraction (7%) of the total number of completion events reported (13,919) in the GHGRP, it can be 

considered a statistically significant number particularly when compared to the number of actual 

completion events (4) identified and used by the EPA in the white paper.

Sorting the GHGRP data for 2011 and 2012 based on known oil producing formations yields the results 

shown in Tables API-1 and API-2 below. These data show several key points that should be considered 

by EPA:

 A majority of reported oil formation completions (64%) utilized REC equipment in 2011 and 

2012.

 Emissions from controlled completion events reported in the GHGRP, 139 Mcf (2.69 tonnes) per 

completion event, are substantially lower than the estimates in most of the studies used by the 

EPA in the white paper and are in the same range as the controlled events identified in the UT 

Study.

 Emissions from uncontrolled completion events reported in the GHGRP, 1,226 Mcf (23.54 

tonnes) per completion event, are lower than most of those estimated in the studies utilized by 

the EPA in the white paper. Compared to the data for gas completion events shown in Table API 

– 2, emissions for uncontrolled and controlled oil completion events are about half of those for 

gas completion events. 

 EPA should utilize these data to more accurately estimate emissions nationwide and more 

reasonably estimate the costs and economic impacts of any proposed regulatory actions. Use of 

these data reduces the uncertainty and effects of inaccurate assumptions that have been made 

in using most of the studies cited in the white paper, most importantly the apparent EPA 
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assumption that all produced gas during the completion phase and that all stranded gas is 

vented without any controls.

Table API – 1: GHGRP Emission Factors for Well Completions and 

Workovers in Oil Formations

15-May-14

Year Category

Total CH4 

Emissions, 

tonnes CO2e # events

tonnes 

CH4/ 

event

scf CH4/ 

event # Data sets

2012 Data

HF completions and 

workovers that vent (nonREC) 77,561 220 

16.79 

 

874,384 25

All Flared HF completions and 

workovers (REC and non-REC) 13,168 186

 

3.37 

 

175,585 22

HF completions and 

workovers with RECs (vented 

only) 9,475 119

 

3.79 

 

197,479 31

2011 Data

HF completions and 

workovers that vent (nonREC) 92,461 124 

35.51 

 

1,849,342 26

All Flared HF completions and 

workovers (REC and non-REC) 11,808 308

 

1.83 

 

95,082 25

HF completions and 

workovers with RECs (vented 

only) 2,768 47

 

2.80 

 

146,071 11

2011 and 2012 Data

HF completions and 

workovers that vent (nonREC) 170,023 344 

23.54 

 

1,225,823 51

All Flared HF completions and 

workovers (REC and non-REC) 24,976 494

 

2.41 

 

125,393 47

HF completions and 

workovers with RECs (vented 

only) 12,243 166

 

3.51 

 

182,924 42
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

and Associated Gas During Ongoing Production June 13, 2014

13

Table API-2: GHGRP Emission Factors for Gas Well Completions and 

Workovers

22-Jan-14

Year Category

Total CH4 

Emissions, 

tonnes CO2e # events

tonnes 

CH4/ 

event

scf CH4/ 

event # Data sets

2012 Data

HF completions and workovers 

that vent (non-REC) 2,722,438 3,070 42.23 2,199,374 258

All Flared HF completions and 

workovers (REC and non-REC) 136,202 1,604 4.04 210,601 156

HF completions and workovers 

with RECs (vented only) 133,652 1,447 4.40 229,079 177

2011 Data

HF completions and workovers 

that vent (non-REC) 3,590,266 2,983 57.31 2,985,059 350

All Flared HF completions and 

workovers (REC and non-REC) 251,273 2,085 5.74 298,896 177

HF completions and workovers 

with RECs (vented only) 178,888 2,730 3.12 162,517 142

2011 and 2012 Data

HF completions and workovers 

that vent (non-REC) 6,312,705 6,053 49.66 2,586,570 608

All Flared HF completions and 

workovers (REC and non-REC) 387,475 3,689 5.00 260,504 333

HF completions and workovers 

with RECs (vented only) 312,540 4,177 3.56 185,575 319

Section 4.2 - Flaring Up

 The conclusion of this report, that “the reason for flaring of the associated gas (in the Bakken

Basin) is the lack of pipeline infrastructure, lack of capacity and lack of compression 

infrastructure” is very significant. API notes that one of the main reasons for the delays in 

constructing the necessary infrastructure has been the slow pace of the Federal government in 

conducting the required evaluations (NEPA, ESA, etc.) and issuing approvals and permits for 

gathering and processing, and other infrastructure.

 This report notes that while a significant fraction of the produced gas cannot be sold due to 

infrastructure limitation, it clearly states that gas is being flared, not vented. While the fraction 

of gas that must be flared may be somewhat unique (although not completely) to the Bakken 

Basin, the fact that it is flared and not vented is not unique to this area. 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

and Associated Gas During Ongoing Production June 13, 2014

14

C. Emission Mitigation Techniques

 In the introduction to Section 5.0, EPA states that “REC is an approach that not only reduces 

emissions but delivers natural gas product to the sales meter that would otherwise be vented.” 

This statement is not accurate and should be revised to state “...otherwise be vented or flared.” 

 API agrees with EPA’s statement that flaring can result in destruction of a valuable resource. As 

noted above, one of the most effective actions that could be taken by the EPA and other 

agencies in the federal government would be to reduce the unnecessary delays in the review 

and approval processes and allow construction of infrastructure wherever it is economically 

viable. This would allow for sale of a majority of the stranded gas that is currently produced and 

flared. In the remaining cases where it is not economic to construct the sales infrastructure, 

then some of the mitigation alternatives identified in the white paper may be considered. 

5.1 Reduced Emission Completions (REC)

 As noted above, the statement in the definition of a REC (Section 5.1.1) that gas is only vented 

without REC technology is not accurate. This statement should be revised to state “...otherwise 

vented or flared...” 

 In discussing the effectiveness of REC (Section 5.1.2), EPA again cites the performance of the 

single well in the UT Study with a greater than 98% reduction in emissions. API again notes that 

the data from that same study shows a greater than 97% emission reduction from the non-REC 

completions cited in that example. In this example, less than 1% improvement in emission 

reduction can be attributed to the use of REC technology. The improvement that can be 

attributed to the REC is that the controlled gas is sold as opposed to flared, which is a 

worthwhile objective, but beyond the scope of the Clean Air Act.

 In discussing the prevalence of use of REC technology, EPA cites the UT Study, which is an 

extremely limited data set (1 REC well). API has provided data extracted from GHGRP submittals 

that shows operators are voluntarily using REC technology in a majority of completions in oil 

formations.

 The EPA fails to address the circumstance of oil wells where use of REC is neither practical nor 

necessary. For the REC technology to work the well must have sufficient flowing pressure and 

produce sufficient quantities of gas to justify the application of the technology. Many oil 

producing regions have formations with oil that donot have sufficient pressure for the well to 

flow naturally or the oil in the formation has very low gas content. In these cases, a pump (rod 

pump or submersible pump) is installed to lift the oil to the surface. Oil from these types of 

formations normally has very low GORs, which means the volume of associated gas is small, 

often essentially zero. This makes the use of REC technology pointless. These conditions should 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

and Associated Gas During Ongoing Production June 13, 2014

15

be addressed in the white paper. The EPA, with assistance from the API, should develop a set of 

minimum criteria for applicability of REC technology. The feasibility of oil well RECs is discussed 

in more detail in the attached API white paper submitted to EPA in March, 2014 but this 

information was apparently not considered for inclusion in EPA’s paper.

5.2 Completion Combustion Devices

 In Section 5.2.4, the EPA states that combustion devices are the most common approach to 

reducing emissions from hydraulically fractured oil wells, yet in this white paper the EPA has 

consistently assumed all gas emissions from completion operations are vented, which is 

incorrect. As noted elsewhere in these comments, API recommends EPA use data that is 

representative of the broad base of industry operations, including data on the actual use of 

combustion devices, in developing and rules for oil completions and associated gas production. 

5.3 Emerging Control Technologies for Control of Associated Gas

 In Section 5.3.1 on NGL recovery, the EERC study used three assumed rich gas flow rates of 300, 

600 and 1,000 Mcfd, with 600 Mcfd being used in the analysis. API notes that the FBFIP data, 

which is a reasonable representation of associated gas production volumes for Bakken Basin oil 

wells, is 351.5 Mcfd which is slightly more than half the flow rate used by the EERC median case, 

and is close to the low end case developed in the study. As a result, for the average case as 

represented in the FBFIP data, recovery economics will be more challenging than the average 

case developed in the EERC study.

 Section 5.3.2 describes natural gas reinjection as a potential technology. The reinjection 

scenario is predicated on injection back into the producing formation. This scenario is highly 

unlikely to work with unconventional formations since formation permeability is extremely low. 

If gas injection into these formations was attempted, injection pressures would be so high that 

the formation fracture pressure would be exceeded, a condition that is not tenable for a long 

term injection operation like this. Therefore, gas injection associated with hydraulically 

fractured oils should not be considered a viable technology.

 Section 5.3.3 describes the potential of generating and using electricity on site. The EPA has 

used the average case from the EERC study (600 Mcfd rich gas flow rate) and carried it forward 

to on site electricity generation. This example assumes, depending on the scenario, generation 

of between 195 to 250 kW/hr. of electricity. The EPA suggests this technology could be 

employed across many well sites in an area, but makes no estimate of what the on-site

electricity demand would be. Since the sites where on-site generation would be considered are 
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

and Associated Gas During Ongoing Production June 13, 2014

16

by definition remote, without access to infrastructure, including the power grid, the applicability 

if this concept is limited. API’s assessment is that on-site electricity demand at these remote 

sites would be very limited (e.g., <10kW/hr. per well) due to limited operational equipment, e.g. 

small pumps, simple oil/gas treating equipment and possibly heat tracing. If artificial lift (pump 

jack) or large volumes of water are being produced, electricity demand would be higher, 

between 75 and 150 kW/hr. per well, depending on the site specific conditions. Thus, a case by 

case evaluation would be required to determine the viability of this concept. Installing 

generation capacity that delivers 20 or more times the electricity than is needed would be 

neither practical nor economical. This option appears to have limited applicability; however, as 

mentioned in the white paper, at least one operator in the Bakken Shale is working with EERC to 

evaluate this technology. 

D. Summary

 The table describing emission estimates provided in the summary significantly overstates actual 

emissions associated with hydraulically fractured oil wells. As has been stated repeatedly in 

these comments, the assumption that all gas produced during flowback operations and all 

associated gas produced at sites that do not have access to adequate infrastructure is vented is 

wrong and should be corrected. It is the EPA’s responsibility to present an accurate and 

representative characterization of industry practices in this white paper.

 API disagrees with the statement that limited information is available on emissions from 

hydraulically fractured oil wells. The API has identified substantially more data within the 

GHGRP data set that has been overlooked by EPA. The API does recognize however, that the 

GHGRP data may also have limitations. The EPA should seriously consider conducting a study to 

gather a representative, multi-basin data set to better characterize these emissions and better 

assess the practicality of some of the emission mitigation options considered in this draft of the 

white paper.

 API rejects the EPA’s estimates of national level emissions since they are only based on 

inaccurate estimates and erroneous assumptions.

 The EPA cites the use and performance of RECs offered in the UT Study, but fails to point out 

that the incremental reduction in emissions due to use of RECs is less than 1%. The incremental 

effectiveness (cost and environmental) of RECs compared to flaring bears further critical 

examination and consideration.
API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions

and Associated Gas During Ongoing Production June 13, 2014

17

 In these conclusions the EPA states that it is their understanding “that most oil well completions 

are controlled with combustion”, yet throughout this white paper has ignored this point and 

used uncontrolled emission volumes to characterize oil well operations. The GHGRP data 

identified by the API provides a reasonable estimate of the percentage of those completion 

events that are controlled and those that are vented. These percentages are likely in a state of 

flux however as implementation of requirements for use of RECs are implemented. While use of 

RECs on oil well completions will not be mandatory, the fact that 77 operators have already 

reported data for oil well completions, demonstrated that this trend will continue and that the 

voluntary use of RECs will increase. 

 The EPA’s evaluation of emission mitigation technologies is superficial and in some cases 

demonstrates a poor understanding of industry operations, economics, and practices. As a 

result, the mitigation technologies identified are likely to be of limited value to operators and 

will continue to face challenges in implementation.
API – March 21, 2014

Hydraulically Fractured Oil Wells

While the process of hydraulic fracturing for gas wells and oil wells is the same, significant differences in 

flowback fluid characteristics will help determine if a REC is feasible for an oil well. This paper discusses 

those differences and the impacts they will have on the application of a REC. 

Important Differences Exist Between Hydraulically Fractured Oil Well and Gas Well Flowbacks

When a gas well is hydraulically fractured, its primary flowback fluid is natural gas. For this reason, REC 

makes sense to reduce the amount of natural gas vented into the atmosphere. For oil wells, however, 

the primary fluid is oil. In some cases, little to no gas is made and may not be seen during the flowback 

process. In other cases, oil wells can be very prolific and a substantial amount of gas can be seen during 

the flowback process. No “one size fits all” standard is appropriate for oil wells. 

Where a REC is feasible for a hydraulically fractured oil well, the procedure for a REC would be similar to 

that of a gas well. Initial flowback will go to a frac tank with some initial venting until a sufficient gas 

flow rate is being returned to operate a separator. Associated gas from the separator will then be 

directed to a combustion device or a gas gathering system as flowback conditions allow with recovered 

liquids going to frac tanks or in some cases storage vessels. One notable difference in oil well RECs 

would be increased utilization of 3-phase separation to recover liquid hydrocarbons in a separate tank 

so these liquids can be sold later. Hydrocarbon liquid volumes in a gas well can frequently be incidental 

to the total liquid flowback volume and 2-phase separation is more common.

However, there are important differences between oil wells and gas wells that make oil well RECs

infeasible in many situations. Two key operating requirements that have the most impact on the 

feasibility of a doing a REC on an oil well are:

 A field wide gas gathering system with sufficient capacity to handle the initial gas production 

surge must be in place

 The oil reservoir must have sufficient pressure and volume of associated gas

A REC is not possible for any hydraulically fractured oil well that doesn’t have both of these 

requirements available. And in many cases, even flaring is not feasible if the reservoir yields insufficient 

gas to either operate a separator or ignite a combustion device. 

A gas gathering system with sufficient capacity must be in place

Gas that is produced from an oil well but can’t be sold is known as “stranded” gas. It’s stranded because 

the pipeline infrastructure needed to gather and transport the gas for processing is not available. Unlike 

gas fields where infrastructure may be unavailable in limited situations such as exploration, delineation, 

or some leasehold wells, gas gathering infrastructure can be unavailable for oil wells across an entire 

field or area. Lack of available infrastructure occurs for various reasons. For instance, insufficient 

associated gas production volumes may make it uneconomic to gather, process, and sell the produced 

gas. Or, economic gas gathering infrastructure construction may lag behind the start of new well 

production, as currently occurs in the Bakken oil shale formation of the Williston Basin in North Dakota. 

During flowback and continuing into production, stranded gas from high pressure wells such as those in 

the Bakken is flared for both reasons of safety and VOC emissions reduction. Without gas gathering 
API – March 21, 2014

infrastructure, an oil well REC is not possible. If stranded gas were not allowed to be flared, wells would 

have to be shut-in and unable to produce.

While it’s imperative that a gas gathering system must be available for a REC, the gathering system must 

also have the capacity to collect the volume of gas produced during a REC at a flow rate sufficient to 

clean out the well. Gas gathering systems are designed to accommodate the maximum anticipated flow 

rate and pressures during the production phase of wells, not necessarily the flowback phase. While this 

could also be a potential issue for certain gas wells, it’s a known issue in the Bakken oil shale where 

limited gas gathering infrastructure exists. Flowing wellhead pressures are high (e.g., 4000 psi), and gas 

volume during initial flowback can spike at a rate many times higher than the flow rate when the well is 

turned over to production. The attached flow rate chart “Example Bakken Oil Well Flowback” shows this 

flow rate spike. Where gathering systems exist, sending all the initial gas volume from flowback through 

the gathering line without properly choking the flow to prevent exceeding the gathering line capacity 

may cause an upset somewhere downstream because of over pressuring the system. Any major upset 

has the potential to result in a serious safety and/or environmental incident. Choking the flowback to 

meet gas gathering capacity can cause poor flowback velocity which inhibits proper cleanout of the well. 

Consequently, a partial REC might be feasible as some of the flowback gas may be able to be sent to 

sales, but remaining gas would need to be flared so as to not overpressure or exceed the capacity of the 

gathering system.

The oil reservoir must have sufficient pressure and volume of associated gas

Many oil reservoirs have pressure that is insufficient for wells to naturally flow on their own even after 

hydraulic fracturing; or they have insufficient pressure to overcome the backpressure of the gas 

gathering system. This can be evidenced by the prevalence of artificial lift such as rod pumps visible 

across the landscape of many oil producing areas. Also, many reservoirs produce insufficient gas 

volumes to operate a separator during flowback which makes both a REC and flaring infeasible. 

Examples of this are reservoirs in the Permian basin in which horizontal drilling is used to extend the life 

of existing producing formations. Other examples include reservoirs in the north central East Texas 

basin which produce heavy black oil, also called “dead oil” because there is no associated gas produced 

with the oil. In this area, gas to operate separation must be purchased as it is not available from well 

production.

In the Permian Basin of West Texas, many oil wells that are hydraulically fractured do not have sufficient 

reservoir pressure to flow back on their own, and there is insufficient gas to flare. Instead, following a 

hydraulic fracture, rod pumps are installed on the wells to artificially lift the fracture fluids either to frac 

tanks or storage vessels. No flowback separators are even installed since there is insufficient gas to 

operate. What little associated casinghead gas is produced with the flowback may be vented through 

the tank.

High pressure reservoirs capable of flowing on their own are needed for REC

Like gas wells, oil well candidates for REC must be capable of flowing on their own even against the 

backpressure of the gathering system. Many of the new oil shale plays that are certainly garnering the 

most interest meet these essential criteria. In oil shale areas such as the Eagle Ford shale in south Texas, 

RECs are already being conducted where both the required parameters of infrastructure and high 

reservoir pressure are present. Gas gathering infrastructure is in place for much of the area, and 

sufficient reservoir pressure and gas volumes exist to make a REC feasible. 
API – March 21, 2014

Reservoirs characterized by the prevalence of artificial lift systems are not good candidates for REC and 

flaring is dependent on sufficient gas being present to be separated and burned.

Flaring is still the best control technology where a REC is infeasible

Where a REC is not feasible, flaring or combusting associated gas is still the only and best technology to 

reduce emissions when sufficient gas volumes exist. In certain situations, operators may use a JouleThomson skid mounted processing plant to collect natural gas liquids from stranded gas, but while this 

may reduce VOC emissions, flaring is still necessary to control gas emissions.

EDF’s March, 2014 report analyzes oil producing shales characterized as “co-producing”

EDF recently released a report in March, 2014 entitled: “Co-Producing Wells as a Major Source of

Methane Emissions: A Review of Recent Analyses”. This study examines methane emissions from 

hydraulically fractured wells drilled in well-known oil shale reservoirs. From this analysis, EDF attempts 

to determine emission factors for the potential of methane emissions during flowback when 

uncontrolled, then uses uncontrolled emissions to project total methane emission reductions if REC and 

emission control were required. EDF also introduces a new, and inappropriate, term “co-producing” as 

a means to describe oil wells producing significant quantities of both oil and gas. We do not support the 

use of this term as it is not consistent with the historical designations used by states, the federal 

government, and industry for over a century. 

While the validity of relying on some of the data collected such as early Subpart W reporting is suspect, 

the methodology to convert this data into emission factors and total projected emission reductions 

seems invalid. EDF acknowledges that emissions from many of the well flowbacks in their data set are 

already controlled through flaring or REC. However, controlled emissions are ignored in favor of making 

their conclusions based on potential uncontrolled emissions. Ignoring emissions based on actual 

practices results in a specious conclusion that inflates the emissions reduction potential of additional 

regulation.

Further, the analysis conducted by EDF appears to be fundamentally flawed by referencing papers 

whose primary intent was not to assess “co-producing wells”, but methane emissions from gas 

production in general. For instance, the UT study referenced by EDF was conducted to assess methane 

emissions from shale gas operations, and some 27 gas flowbacks from hydraulically fractured wells were 

measured. It was coincidental that six of these wells also produced oil and EDF selected these six as a 

subset and conducted their own analysis on these wells, assuming that the emissions were not 

controlled (when in fact they were). These six wells do not represent enough of a sample size to draw 

any conclusions from “co-produced wells”, and the UT study authors would likely not have conducted 

such an analysis of such a small sample set themselves. EDF takes a similar approach with the 

Novim/Brandt data, where they use a subset of the Novim dataset and use the unfounded assumptions 

in the Novim study (“it is assumed that production during flowback increased linearly with time for 9 

days prior to initial production and all such methane emissions were vented or understood differently 

that completions emissions correspond to 4.5 days of initial gas production”) to draw their conclusions. 
API – March 21, 2014

In both cases, they are relying on small subsets of the intended references studied to draw extreme or 

unfounded conclusions that the original study authors chose to disregard or not pursue for valid 

reasons. 

When oil wells produce high volumes of gas during flowback, flaring at the very least is necessary to 

mitigate safety concerns. Where gas gathering infrastructure is available, REC is also employed by many 

operators to capture saleable product. With both flaring and REC being a practical reality for most of 

these wells already, EDF’s mischaracterization of potential emission reductions stands out as erroneous 

and a misrepresentation of current operating practices.

Conclusion

Only wells with sufficient reservoir pressure to flow against the gathering system back pressure and 

capable of producing saleable quantities of natural gas are candidates for REC. Without a gas gathering 

system, flaring is still the next best option to control gas emissions during flowback. While high 

pressured oil shales are in the public focus, hydraulic fracturing also occurs in many low pressure 

formations that rely on artificial lift to assist flow. These wells are not good candidates for REC. When 

REC is not feasible, flaring during flowback is the next best option provided sufficient gas is available.

When evaluating the need for further regulation, potential emission reductions must be determined by 

looking at actual emissions based on current operating practices that already include REC or flaring by 

necessity in many cases. For the many operators already employing REC without regulation, the real 

cost effectiveness of becoming regulated is not measurable. 

Recommended Charge Questions for Peer Reviewers

 Do the data sources and studies that the paper relies upon appear credible and complete?

 Was sufficient QA/QC conducted with regard to the data sources and studies that the paper 

relies on to determine their applicability and validity?

 Does the paper identify and thoroughly discuss the two necessary operating conditions (i.e., 

reservoir pressure and infrastructure) that make REC possible for any well?

 Does the paper adequately describe the limitations of when a REC can be performed?

 Does the paper adequately identify known reservoirs or basins where following REC procedures 

will be problematic?

 Does the paper adequately describe the limitations and situations of when flaring can’t occur?

 Does the paper adequately identify and discuss low pressure reservoirs and provide reasons 

why REC or flaring may not be feasible?

 Is the paper realistic in its evaluation of actual emission reduction potential from additional 

regulation?
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Gas Flow Rate (MCF)

Example Bakken Oil Well Flowback

Gas Flow Rate Water Flow Rate Oil Flow Rate