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 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 additi onal 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 provide d technical feedback and expertise throughout the de velopment of the New Source
Per formance Standard (NSPS) Subpart OOOO rule

. Each source addressed by the white papers w as considered 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 fu ll 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 techn ical 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 d ecisions 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 response 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 d ocument 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 im prove 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 so urces. 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

governmen t agency policy decisions, w e 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 1 3 , 2014

i 

## Table of C ontents

Executive Summary

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

A. Specific Comments

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

B. Emissions Data and Estimates

................................ ................................ ................................ ............... 7

C. Emission Mitigation Techniques

................................ ................................ ................................ ......... 14

D. Summary

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

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 2014

2 

## 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 solidi fy its understanding of the methane and volatile organic compounds (VOCs) emissions from these sources in this industry

sector. The American Petroleum Institute (API) her e by 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 whi te 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 hydraulical ly 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,
part icularly 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 overstatin g 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 cit ed 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 t hat are acceptable to the
operator.API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 2014

3 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 tec hnologies. 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 a ccurate 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 st rongly 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 methan e emission vol umes

.

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 exampl es 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 descri ptions 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 ratherAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 2014

4 than being flared. It is incumbent on EPA to use the best availabl e 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 a nd 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 emissio ns 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 t he 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 pa ragraph 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. Hydrau lic 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 phas e 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 d evelopment” 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 recomple tion 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 and Associated Gas During Ongoing Production June 1 3 , 2014

5 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 inter val 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 prod ucing 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 w ell 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, CO 2 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 fract ure 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 doe sAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 2014

6 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 inco rrectly 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 vi scosity 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 de scribe 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 Nor th 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 w ell (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 vente d. 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 1 3 , 2014

7 Additionally, the DI database used to compile the data does not identify the disposition of produced gas, which makes drawing the conclusion made by t he 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 thei r 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 treatmen t (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 th eir 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 B erthold 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 wereAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 2014

8 found to be indus try 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 t hese 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, signi ficant 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 fo rmations 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 applicabi lity. 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

stat ed 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 d iscussion 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. an d 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 toAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 2014

9 present a more acc urate 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 fo r 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 d escribe 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 e stimated 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 compl etion 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 VOC s 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 r eplicate 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% whenAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 2014

10 compared to a flare. The API recommends that the incremental redu ction 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 incorrectl y 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

c ompletion 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 tha t 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 em issions 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 Fract ured 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

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 2014

11 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 infor mation 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 info rmation 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 ide ntified 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 c ompletion 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 equi pment 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 estimat e 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 i n the white paper, most importantly the apparent EPAAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 2014

12 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 (non

REC) 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 (non

REC) 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 (non

REC) 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 42API Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 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 du e 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 un ique 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 1 3 , 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 stateme nt 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 Reduce d Emission C ompletions (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 effectiv eness 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

- RE C 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 su bmittals 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 t he 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 shouldAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 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 technolog y. 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 vente d, 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 a nd 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 tec hnology. 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 formation s 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 o ils 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 el ectricity 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 s ites 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 areAPI Comments on Submitted to EPA

Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production June 1 3 , 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

- sit e 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 determin e 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 corre cted. 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 oi l 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
gat her 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 1 3 , 2014

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

are contr olled 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 compl etion 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 fa ct 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 cas es 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

W hen 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, littl e 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 operat e 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 oi l 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 a nd 2

- phase separation is more common.

However, there are importan t differences between oil wells and gas wells that make oil well REC s infeasible in many situations. Two key operating requirements that have the most impact on the feasibility of a doi ng 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 gather ing 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 av ailable infrastructure occurs for various reasons . For instance
, insufficient associated gas production volume s may make it un economic 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 bo th reasons of safety and VOC emissions reduction. Without gas gatheringAPI

– 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 ga s 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 maxi mum 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 infr astructure 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 Bak ken Oil W ell F lowback ” 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 u pset 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 inh ibits 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 syste m.

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

Many oil reservoirs have pressure that is insufficient for well s to naturally flow on their own even after hydraulic fracturing ; or they have insufficient pressure to overcom e 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 sep arator 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 install ed 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 ma y 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 t he new oil shale plays that are certainly garnering the most interest meet these essential criteria

. In oil shale areas such as the Eagle F ord shale in south Texas, RECs are already being conducted where both the required parameters of infrastructure an d 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

R eservoirs 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.

F laring 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 Joule

Thomson skid mounted processing plant to collect natural gas liquids from stranded gas, but while this may reduc e 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 en titled: “ C o

- P roducing W ells as a M ajor S ource of

M ethane E missions : A Review of Recent Analyses”. This study examines methane emissions from hydraulic ally fractur ed wells drilled in well

- known oil shale reservoirs. From this analys i s, EDF attempts to determine emission factors for the potential of metha ne 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 descri be 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 coincid ental 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). T he se 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 differen tly that completions emissions correspond to 4.5 d ays 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 stu dy 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 e mployed 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 curre nt operating practices.

Conclusion

Only wells with sufficient reservoir pressure to flow against the gathering system back pressure and capable of produc ing 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 evaluat ing 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 m any cases. For th e many operators already employ ing 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 rega rd 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 pos sible 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?02004006008001,0001,20005001,0001,5002,0002,5003,0003,500 11/21/2013 11/22/2013 11/23/2013 11/24/2013 11/25/2013 11/26/2013 11/27/2013 11/28/2013 11/29/2013 11/30/2013 12/1/2013 12/2/2013 12/3/2013 12/4/2013 12/5/2013 12/6/2013 12/7/2013 12/8/2013 12/9/2013 12/10/2013 12/11/2013 12/12/2013 12/13/2013 12/14/2013 12/15/2013 12/16/2013 12/17/2013 12/18/2013 12/19/2013 12/20/2013 12/21/2013Day1Day2Day3Day4Day5Day6Day7Day8Day9Day10Day11Day12Day13Day14Day15Day16Day17Day18Day19Day20Day21Day22Day23Day24Day25Day26Day27Day28Day29Day30Day31 Oil and Water Flowrate (BBLS)

Gas Flow Rate (MCF)ExampleBakkenOilWellFlowbackGasFlowRateWaterFlowRateOilFlowRate