## Attachment A
Hydraulically Fractured Oil Wells David Allen University of Texas at Austin

### Comments on


## Oil and Natural Gas Sector Hy draulically Fractured Oil Well Completions and Associated Ga s during Ongoing Production Draft dated April, 2014 Submitted to: Carrie Richardson Fry Research Triangle Institute Submitted by:

David Allen June 16, 2014

Overview I have reviewed the draf t white paper titled “Oil and Natura l Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas duri ng Ongoing Production” pr epared by the U.S. EPA Office of Air Quality Planning and St andards (OAQPS), dated April 2014. I have concentrated my review on my areas of expertis e. My comments identify additional information available from a recent set of measurements of methane emissions from natural gas and oil well completion flowbacks (Allen, et al., Proceedings of the National Academy of Sciences, 110, 17768-17773, and publicly available supporting informati on, referred to as Al len, et al., 2013 in this document). My comments also describe some important features of the available data. The review is organized into two sections: responses to the charge questions for reviewers that appear in the white paper, and additional specific comments, organized by page number.Responses to charge questions 1. Please comment on the national estimates and per well estimates of methane and VOC emissions from hydraulically fractured oil well co mpletions presented in this paper. Are there factors that influence emissions from hydraulica lly fractured oil well completions that were not discussed in this paper? Response: Measurements of emissions from completion flowbacks ar e extremely limited, as noted in responses to subsequent charge quest ions. This creates un certainties in national emission estimates. 2. Most available information on national a nd per well estimates of emissions is on uncontrolled emissions. What information is ava ilable for emissions, or what methods can be used to estimate net emissions from uncontrolled emissions data, at a national and/or at a per well level? Response: Net emissions are estimated by estim ating potential emissions , then reducing those emissions by a control efficien cy factor. In the data report ed by Allen, et al. (2013), measurements were made of control efficiencies for 18 well completion flowbacks. These wells controlled emissions either through flaring of flowback gas es or through capture of the gases and routing the gases to sales. Of the potential emissions for these 18 wells (emissions if the well had not had control technologies installed), 99% we re captured or combusted. This control effectiveness is based primarily on a group of direct measurements, but it was necessary to assume the destruction efficiency for materials sent to flares. The assumed destruction efficiency was 98%; th is assumption is consistent with the limited data available on these flares. Allen, et al. (2013) reported measurements of combustion efficiency of a flare on a well completion site, and these data suggested very high flare destruction efficiency (>99%). Thus, overall control efficienc ies in the range of 98-99% we re observed for 18 wells on which emission control equipmen t was installed during completi on flowbacks. Many, but not all of these wells were gas wells (see response to Question 4). For the limited number of oil wells (defined in the white pap er as a gas to oil ratio of 12,500 scf/bbl or less) on which measurements were made, control effici ency was also in the range of 98-99%. The data reported by Allen, et al, also suggest some possible methods for assembling additional data on potential emissions and control efficiencies. Each of the 18 wells with controls, on which Allen, et al. (2013) made me asurements, utilized a separator. The vast majority of the flowback gas was associated w ith the vapor stream leaving the separator. Relatively little gas volatilized from flowback tanks or was released to the atmosphere due to initial flow into an open top tank. Therefore, the overall control efficiency for the flowbacks were dominated by the fate of the separator vapor stream. If that stream is sent to a flare, the overall control efficiency will be similar to that of the flare for many wells. If the gas is recovered and sent to sales, the cont rol efficiency can be close to 99+%. 3. Are further sources of information available on VOC or methane emissions from hydraulically fractured oil well completions beyond those described in this paper?Response: I am not aware of any additiona l direct measurements of emissions. 4. Please comment on the various approaches to estimating completion emissions from hydraulically fractured oil wells in this paper.

a. Is it appropriate to estimate average uncontrolled oil well completion emissions by using the annual average daily gas production during the first year and multiplying that value by the duration of the aver age flowback period? Response: The data reported by Allen, et al. (2013), that is cited and reproduced in Table 3-6 of the white paper, can be used to compare average daily gas production to uncontrolled (potential) emissions. Focusing just on the wells that the white paper has identified as oil wells (GC-1, GC-2, GC-3 and GC-7), the potential emissions, reported by Allen, et al. (2013) and cite d in Table 3-6 of the white p aper, can be compared to the product of the gas production for the same wells, (reported in Table S1-6 of Allen, et al. (2013), Supporting Information) and the duration of the event (cited in Table 3-6 of the white paper). These data are summarized in the Table below: Well Potential methane emissions* (Mcf) Gas production rate (first 30 day avg.)**

(Mcf/d) Duration of flowback*

(Days) Gas production rate x duration x x 47% methane (Mcf) Ratio of measured potential emissions to estimate based on

duration and gas production GC-1 5,005 3,000 75/24 4406 1.14 GC-2 4,205 2,700 76/24 4018 1.05 GC-3 21,500 1,300 28***/24 713 30.7*** GC-7 4,320 1,500 108/24 3172 1.4 *As cited in Table 3-6 of the white paper **From Allen, et al. (2013), Supporting Information, Table S1-6 ***Ambiguity in duration of event, see text below For three of the four wells, (all with flaring of gas during the completion) the measured potential emissions are comparable to the emissions estimate (based on the method described in the white paper); the ratio of th e measurements to the estimate has a value near 1. For one well, the potential emissions ar e much larger than the estimate. For this well the critical issue is the flowback period. In reporting results, Allen, et al. (2013) note that different companies had different practices in defining the end of a completion flowback. For example, some companies might define the end of the flowback as the time at which gas is first routed to sales. Other companies might de fine the end of the flowback as the time at which flow is rout ed to permanent, rather than temporary completion equipment. No single, consistent de finition is in use. Details for the specific case of well GC-3 are described in study appendi ces from Allen, et al. (2013; available at the study web site http://dept.ceer.utexa s.edu/methane/study ). This well had an initial flowback to an open top tank that lasted for 28 hours. After 28 hours, the flow was directed to a separator and the gas from the separator was then sent to sale s and a flare. In this case 28 hours was defined as the dur ation of the flowback, as reported by the company, since gas had begun to go to sales. The study team re ported emissions fromt h 2 T d r e t h b. I s
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a an a nk 1 et s tudyseparator vapor stream. If that stream is sent to a flare, the overall control efficiency will be similar to that of the flare for many wells. If the gas is recovered and sent to sales, the control efficiency can be close to 99+%. In addition, the amount of gas leaving the completion separator is often very close to the potential emissions from the well. Therefore, collecting information about gas flows from completion separators has the potential to generate a large body of data on potential emissions from comp letion flowbacks. 6. Please comment on the methodologies and data sources that you believe would be appropriate to estimate the rate of recompleti ons of hydraulically frac tured oil wells. Can data on recompletions be used that does not differentiate between conventional oil wells and hydraulically fractured oil wells be reasonably used to estimate this rate? For example, in the GHG Inventory, a workover rate of 6.5% is applie d to all oil wells to estimate the number of workovers in a given year, and in the ERG/ECR analysis above a rate of 0.5% is developed based on both wells with and without hydrauli c fracturing. Would these rates apply to hydraulically fractured oil well s? For hydraulically fractured gas wells, the GHG Inventory uses a refracture rate of 1%. Would this rate be appropriate for hydraulically fractured oil wells? Response: No response – this question is outside the scope of my expertise. 7. Please comment on the feasibility of the use of RECs or completion combustion devices during hydraulically fractured oil well completion operations. Please be specific to the types of wells where these technologies or processes are feasible. So me characteristics that should be considered in your comments are well pressure , gas content of flowback, gas to oil ratio (GOR) of the well, and access to infrastructure. If there are additional factors, please discuss those. For example, the Colorado Oil and Ga s Conservation Commissi on requires RECs only on “oil and gas wells where reservoir pre ssure, formation productivity and wellbore conditions are likely to enable the well to be capable of naturally fl owing hydrocarbon gas in flammable or greater concentra tions at a stabilized rate in excess of five hundred (500) MCFD to the surface against an induced surface backpressure of five hundred (500) psig or sales line pressure, whichever is greater” Response: No response – this question is outside the scope of my expertise. 8. Please comment on the costs for the use of RECs or completion combustion devices to control emissions from hydraulically fractured oil well completions. Response: No response – this question is outside the scope of my expertise. 9. Please comment on the emission reductions th at RECs and completi on combustion devices achieve when used to control emissions from hydraulically fractured oil well completions. Response: As noted in the response to Ques tion 2, Allen, et al. (2013) measured overall control efficiencies in the range of 98-99% fo r 18 wells on which emission control equipment was installed during completion flo wbacks. Many, but not all of these wells were gas wells (see response to Question 4). Fo r the limited number of oil wells (defined in the white paper as a gas to oil ratio of 12,500 scf/bbl or less) on which measurements were made, control effectiveness was also in the range of 98-99%.10. Please comment on the prevalence of the use of RECs or completion combustion devices during hydraulically fractured oil well comp letion and recompletion operations. Are you aware of any data sources that would enable estimating the prevalence of these technologies nationally? Response: No response – this question is outside the scope of my expertise. 11. Did the EPA correctly identify al l the available technologies fo r reducing gas emissions from hydraulically fractured oil well co mpletions or are there others? Response: No response – this question is outside the scope of my expertise. 12. Please comment on estimates of associated ga s emissions in this paper, and on other available information that would enable es timation of associated gas emissions from hydraulically fractured oil wells at the national- and the well-level. Response: No response – this question is outside the scope of my expertise. 13. Please comment on availability of pipeline in frastructure in hydrau lically fractured oil formations. Do all tight oil plays (e.g., the Permian Basin and the Denver-Julesberg Basin) have a similar lack of infrastruc ture that results in the flaring or venting of associated gas? Response: No response – this question is outside the scope of my expertise. 14. Did the EPA correctly identify all the availa ble technologies for re ducing associated gas emissions from hydraulically fractured oil well s or are there others? Please comment on the Colorado Department of Natural Resources : Oil and Gas Conservation Commission Rule 805.b(3)A. (http://cogcc.state.co.us/) costs of these technologies when used for controlling associated gas emissions from hydraulically fractured oil wells. Please comment on the emissions reductions achieved when these tec hnologies are used for controlling associated gas emissions from hydrauli cally fractured oil wells. Response: No response – this question is outside the scope of my expertise. 15. Are there ongoing or planned studies that will substant ially improve the current understanding of VOC and methane emissions from hydraulically fractured oil well completions and associated gas and availabl e options for increased product recovery and emission reductions? Response: See response to Questions 3 and 5.Specific Comments Page 11, Table 3-2: The first two rows may be labelled inco rrectly. It is unclear, for example, how a maximum molecular weight for VOCs coul d be 31.7, while the maximum molecular weight for natural gas is listed as 51. Page 27: The white paper states that a completion co mbustion device will achieve an average of 95% control. Limited measurements made by Al len, et al. (2013) suggest that this control effectiveness may be as high as 99%. Page 48: The Allen, et al. reference cited at multiple points in the document is missing.