1 C O -P RODUCING W ELLS AS A M AJOR S OURCE OF M ETHANE E MISSIONS :

A R EVIEW OF R ECENT A NALYSES

P REPARED BY E NVIRONMENTAL D EFENSE F UND

M ARCH 2014

The Environmental Protection Agency’s (“EPA’s”) New Source Performance Standards (“NSPS”) for the oil and natural gas sector require that hydraulically fractured natural gas wells reduce their completion emissions using either redu ced emission completions (“RECs”) or flaring. 1 EPA defines a “gas well” or “natural gas well” as “an onshore well drilled principally for production of natural gas” 2 and, depending on how this definition is interpret ed, a number of wells that co-produce oil (or other liquids) and na tural gas (“co-producing wells”) may not need to control their emissions under the REC requiremen ts in the NSPS.

Many completions of these co-producing wells, howev er, produce substantial pollution that can be cost-effectively mitigated using the sa me clean air measures that have effectively reduced emissions from hydraulically fractured gas wells. Extending clean air protections to coproducing wells is vital given recent trends within the oil and gas industry. Over the last two years, rising oil prices and low natural gas prices have caused new drilling activity to increasingly shift to shale formations rich in oil and condensates. Reflecting this trend, the U.S. Energy Information’s (“EIA’s”) most recent **Annual Energy Outlook** predicts that domestic oil production will grow significantly through 2020, dr iven primarily by increases in tight oil production (see Figure 1).

Figure 1. US Petroleum and Other Liquids Supply, 1 970-2040 (EIA)

1 With limited exceptions, all fractured and refract ured natural gas wells will be required to use RECs as of January 1, 2015. 77 Fed. Reg. 49,490, 49,497 (Aug. 16, 2012 ).

2 40 C.F.R. § 60.5430.2

This analysis synthesizes available information on per-completion emissions factors, the cost-effectiveness of mitigating those emissions us ing RECs or high-efficiency flaring, and, where possible, the total amount of methane that wo uld be reduced by deploying these completion protections at co-producing wells. Tabl e 1 synthesizes data from the following

sources:

• A February, 2014 Stanford/Novim Study in the journa l Science entitled “ **Methane Leakage from North American Natural Gas Systems**  ;” (“Stanford/Novim Analysis”) 3

• ICF International’s Report from March, 2014 entitle d “ **Economic Analysis of Methane Emissions Reduction Opportunities in the U.S. Onsho**  **re Oil and Natural Gas Industries**  ;” (“ICF Report”) **4**

• A 2013 analysis in the Proceedings of the National Academy of Sciences led by the University of Texas entitled “ **Measurements of methane emissions at natural gas production sites in the United States**  ;” 5 (“UT Study”)

• EDF’s analysis of the oil and natural gas portion o f EPA’s Greenhouse Gas Reporting Program (“EDF Subpart W Analysis”); 6 and

• An analysis completed by EDF and Stratus Consulting of well completion reports in the Bakken, Eagle Ford, and Wattenberg field (“EDF/ Stratus Analysis”).

These sources all indicate that co-producing well c ompletions are a substantial source of methane emissions, with total estimated emissions m uch larger than the figure reported in EPA’s official inventory of greenhouse gas emission s. EPA’s current emission factor for coproducing wells derives from a 1996 study of conven tional oil wells, and very likely underestimates emissions from the hydraulic fractur ing techniques that are prevalent today.

3 A.R. Brandt et al., **Methane Leaks from North American Natural Gas Syste ms**  , 343 S CIENCE 733 (Feb. 14, 2014), available at http://www.novim.org/images/pdf/ScienceMethane.02.1 4.14.pdf

.

4 The report is available at http://www.edf.org/sites/default/files/methane_cost _curve_report.pdf

.

5 David T. Allen et al., **Measurements of methane emissions at natural gas pr oduction sites in the United States** 
, PNAS Early Edition (2013), **available at** www.pnas.org/cgi/doi/10.1073/pnas.1304880110

.

6 EDF, Comments on “Draft Inventory of U.S. Greenhou se Gas Emissions and Sinks: 1990–2012” (included in the supplemental information for this analysis).3

TABLE 1: Summary of Co-producing Emissions, Cost-Ef fectiveness, and Mitigation Potential

Data Sources Potential

Emission Factor (MT CH 4 ) National

Emissions Estimates*** (MT CH 4 ) REC Cost

Effectiveness ($/MT CH 4 ) Flaring Cost

Effectiveness ($/MT CH 4 ) Methane

Mitigation Potential (MT CH 4 ) without savings with

savings Stanford/ Novim Analysis* 40.2 7 120,000**** 778 92 114,000

ICF Report 6.6** 96,000 n/a n/a 96.57 94,000 UT Study * 193.5 153.8 -132.7 8 19.19 n/a EDF Subpart W Analysis 21.8 163,000 1,435 170 140,000

EDF/Stratus Analysis 15.7 247,000 3,578 3,314 424 235,000

*Analysis includes potential emissions factor only. Cost-effectiveness and mitigation potential derived using common assumptions described below. ** This EF includes both vented emissions controlle d emissions so is not a true potential emissions factor. *** Estimates provided by the authors of each indiv idual study.   This estimate only reflects emissions from thr ee major production basins, and therefore understates total national emissions.

The remainder of this white paper provides additio nal information on the development of an emission factor for co-producing wells, the c ost-effectiveness of mitigating these emissions, and overall methane mitigation potential s.

Potential Emission Factor

The above-described analyses determine potential em issions factors for co-producing well completions using several different methods, i ncluding direct measurement, analysis of Subpart W data, and analysis of initial oil and gas production. All of these analyses find potential emissions are significantly greater than the emissions factor for oil well completions currently in EPA’s annual greenhouse gas inventory (0.0141 tons of methane per completion). Given that EPA’s current emissions factor is dated and was based on emissions from completions of conventional, non-hydraulically frac tured wells, the more recent studies described below suggest that the official inventory is likely underestimating the extensive methane emissions from co-producing well completion s. Moreover, neither the current NSPS

7 Weighted average of emission factors for wells in the Bakken, Eagle Ford, and Permian Basins.

8 On average, these wells would achieve net savings of $25,630 by selling gas recovered during completi ons, assuming $4/Mcf.4

nor the regulations of most states require control of completion emissions from co-producing wells. 9

** UT Study.** The UT Study measured various large sources of meth ane in the production sector, including 27 well completions in various ge ographic areas across the country. Six of the measured completions were at co-producing wells tha t produced significant amounts of hydrocarbon liquids, 10 and, for each of these completions, researchers di rectly measured potential and actual methane emissions. Actual com pletion emissions from these co-producing wells ranged from 1.7 to 5.0 metric tons (“MT”) CH 4 , though all of the wells controlled completion flowback emissions with either flaring o r a combination of RECs and flaring. The UT study estimated potential emissions as the total vo lume of gas vented, flared, and sent to sales from initiation of flowback until the reported comp letion end time. The potential emissions from these wells, which would be more indicative of uncontrolled completions, ranged from 81.9 to 414.4 MT CH 4 , with an average value of 193.5 MT of CH 4 /completion. 11

Table 1. Measured and potential emissions of co-pro ducing wells from Allen, et al. (2013)

Completion Event Emission

Controls Measured

Emissions (scf CH 4 ) Potential

Emissions (scf CH 4 ) Measured

Emissions (MT CH 4 ) Potential

Emissions (MT CH 4 ) GC-1 Flaring 105,000 5,005,000 2.0 96.4 GC-2 Flaring 90,000 4,250,000 1.7 81.9

GC-3 REC &

Flaring 260,000 21,500,000 5.0 414.1

GC-4 REC &

Flaring 180,000 13,000,000 3.5 250.4
GC-6 Flaring 247,000 12,200,000 4.8 235.0 GC-7 Flaring 90,000 4,320,000 1.7 83.2 Average 162,000 10,030,000 3.1 193.5

**Subpart W Analyses.** EDF also evaluated completion data from 2011 and 20 12 that was reported to EPA under its greenhouse gas reporting rule for oil and gas systems (known as “Subpart W”). 12 Subpart W does not require reporting of oil well completion and workover

9 Notably, Colorado does require that co-producing w ells perform reduced emission completions. Co. Oil & Gas Conserv. Comm’n (“COGCC”) Rule 805(b)(3)(A).

10 David T. Allen et al., **Measurements of methane emissions at natural gas pr oduction sites in the United States** 
, PNAS Early Edition (2013), **available at** www.pnas.org/cgi/doi/10.1073/pnas.1304880110

. **See also** EDF, Analysis of Co-Producing Well Completions (updated Mar. 2013) ( included in the supplemental information for this a nalysis).

11 EDF, Analysis of Co-Producing Well Completions (De c. 2013). The underlying study analyzed a total of 26 well completions.

12 EDF, Comments on “Draft Inventory of U.S. Greenhou se Gas Emissions and Sinks: 1990–2012” (included in the supplemental information for this analysis).5

emissions. Nonetheless, in 2011 and 2012 there wer e 1,754 reports of completions and workovers from wells in formations classified under Subpart W as “oil formations.” EDF performed a separate analysis of DI Desktop data to assess if these completions were actually oil wells. 13 In approximately 75% of the counties from which th ese completion reports came, over half of the wells with first production in 201 1 & 2012 were oil wells. Using the same approach that EPA used to estimate emission factors for completions from the entire GHGRP dataset, EDF has derived emission factors for this subset of wells located in oil formations (Table 3). The average emission factor for all oil formation completion and workovers is 6.2 MT CH 4 /event, or more than 400 times higher than the curr ent oil well completion emission factor. EDF also developed separate emission factors for ea ch combination of emission controls reported under Subpart W: uncontrolled (“vented”) c ompletions, completions controlled with a flare, completions controlled with a REC, and compl etions controlled with both flares and REC. The emission factors for the four categories range from 3.1 MT CH 4 /event for completions with
REC to 21.8 MT CH 4 /event for vented completions.

The ICF Report also uses Subpart W data to develop an emission factor for hydraulically fractured oil wells. From this data, the Report de velops an emissions factor of 344,000 scf CH 4 /completion or 6.6 MT CH 4 /completion, which is an average value including bo th controlled and uncontrolled completions.

Table 3. Oil well completion and workover emission factors developed from 2011 & 2012 GHGRP Subpart W oil formation type sub-basins using the same method as EPA for developing the natural gas completion and workover emission factors

Category Completions

(# events) Workovers

(# events) Completions

& Workovers (# events) Completions

EF (MT CH 4 /event) Workovers

EF (MT CH 4 /event) Completion

& Workover EF (MT CH 4 /event)
Vent 320 147 467 21.8 7.6 17.3 Flare 221 66 287 3.7 2.5 3.4 REC 186 0 186 3.1 N/A 3.1 REC+Flare 17 0 17 11.7 N/A 11.7 Ambiguous 708 89 797 1.5 0.0 1.3 All events 1,452 302 1,754 6.6 4.2 6.2

**Initial Production Analyses** . The Stanford/Novim Analysis evaluated 2,969 well completions in the Bakken, Eagle Ford, and Permian basins for 2011 using the DrillingInfo HPDI Database. 14 The analysis estimated potential emissions from t hese tight oil wells by converting

13 Data obtained from DrillingInfo, DI Desktop, http://info.drillinginfo.com/products/di-desktop/

. 14 A.R. Brandt et al., **Methane Leaks from North American Natural Gas Syste ms**  , 343 S CIENCE 733 (Feb. 14, 2014), available at http://www.novim.org/images/pdf/ScienceMethane.02.1 4.14.pdf . The relevant data is contained in the supporting documentation for the study ( http://www.sciencemag.org/content/suppl/2014/02/12/ 343.6172.733.DC1/Brandt.SM.datafile.xlsx ).6

peak gas production to a daily initial production r ate. It then assumed that production during flowback increased linearly with time for 9 days pr ior to initial production and all such methane emissions were vented, or understood differently, t hat completion emissions correspond to 4.5 days of initial gas production. 15 Using this methodology, the analysis determined p otential emissions factors for the Bakken (31.1 MT CH 4 /completion), Eagle Ford (90.9 MT
CH 4 /completion), and Permian (31.2 MT CH 4 /completion) Basins.

The EDF/Stratus analysis takes a similar approach, using initial production values to understand potential completion emissions at co-pro ducing wells. Stratus Consulting initially performed an analysis of 100 well completions in th e Bakken, assuming a 7 to 10 day completion event with gas production increasing fro m zero to the initial production value in a non-linear fashion over the course of the completio n. Accordingly, Stratus assumed that total gas production over the 7-10 day completion event w ould equal 3 average days of gas production. 16 As with the Stanford/Novim analysis, Stratus assum ed all of this gas was vented.

EDF subsequently extended this analysis to approxim ately 9,500 wells in the Bakken, Eagle Ford, and Wattenberg fields. 17 Only oil wells were analyzed for the Eagle Ford an d Wattenberg fields; North Dakota does not distinguis h between oil and gas wells so all Bakken wells were assumed to be oil wells. Across all well s, the analysis found an average potential emissions factor of 15.7 MT CH 4 /completions with averages of 18.0, 24.7, and 9.5 M T CH 4 /completion in the Bakken, Eagle Ford, and Wattenbe rg respectively.

Cost Effectiveness

Other than the ICF Report, none of the above non-ED F analyses calculated the costeffectiveness of controlling completion emissions u sing RECs or high-efficiency flaring. Accordingly, we applied consistent cost assumptions to all of the analyses above, except the ICF Report. For RECs, we assumed 95% control efficienc y and used EPA’s cost of performing a reduced emission completion ($29,713) 18 to calculate cost-effectiveness. Across all studi es, we calculated a REC cost-effectiveness without a credi t for captured gas ranging from $154 - $3,578/MT CH 4 reduced. Using production data from approximately 9,500 wells in the Bakken, Eagle Ford, and Wattenberg fields, we calculated a REC cost-effectiveness with credit for gas

15 This methodology is set forth in Francis O’Sulliva n & Sergey Paltsev, **Shale gas production: potential versus actual greenhouse gas emissions**  , E NVTL

. R ES

. L ETTERS 7(4):044030 (Nov. 26, 2012).

16 Memorandum from Leland Deck, Stratus Consulting, t o Peter Zalzal and Vickie Patton, Environmental Defe nse Fund, re: Methods Memo on VOC Cost-Effectiveness in Controlling Bakken Shale Combined Oil and Gas Wells During Well Completion (Mar. 30, 2012) (included in the supplemental information for this analysis).

17 EDF, Spreadsheets analyzing Bakken, Eagle Ford and Wattenberg wells (included in the supplemental information for this analysis).

18 EPA, **Oil and Natural Gas Sector: Standards of Performanc e for Crude Oil and Natural Gas Production,**  **Transmission, and Distribution, Background Technica l Support Document for Proposed Standards**  (July 2011), **available at** http://www.epa.gov/airquality/oilandgas/pdfs/201107 28tsd.pdf

.7

capture. With a credit for gas savings (based on an assumed gas price of $4.00/Mcf), we calculated a median cost-effectiveness of $3,314/MT CH 4 reduced and also calculated costeffectiveness for the top 25% and top 10% of wells, as shown in the table below.

Table 4. EDF / Stratus REC Cost-Effectiveness for M edian and Top 25 and 10 Percent of Wells

Percentile REC Cost

Effectiveness with gas capture credit ($/MT CH4) Mitigation

Potential (MT CH4) Mitigation

Potential (% of total)

10% $544 60,643 40.9 25% $1,266 97,430 65.7 50% $3,314 126,508 85.3

To calculate flaring cost effectiveness, we assumed 95% destruction and removal efficiency (“DRE”) and multiplied this by the emiss ion factor to get flaring emission reductions. We then divided the EPA cost estimate of flaring co mpletion emissions from a well ($3,523) by the flaring emission reductions for each of the ana lyses. 19 Across all studies (excluding the ICF Report) we calculated a flaring cost-effectiveness ranging from $19 - $424/MT CH 4 reduced.

The ICF Report includes its own cost assumptions ab out performing high-efficiency flaring, which are substantially higher than those in EPA’s NSPS. ICF assumes flaring has a 98 percent control efficiency and a capital cost of $5 0,000, with an additional $6,000 in fuel costs for ignition. ICF estimates the cost-effectiveness of flaring to be $1.86/Mcf of methane ($97/MT CH 4 ) for completion gas. The ICF report did not exami ne the cost-effectiveness of RECs for co-producing wells.

Mitigation Potential

Determining inventory-wide mitigation potential re quires scaling up emissions nationally and then applying percentage reductions associated with mitigation technologies. The Stanford/Novim Analysis, the ICF Report, the ED F Subpart W Analysis, and the EDF/Stratus Analysis all provide national estimates of emission s from co-producing wells, which we describe in greater detail below. The UT Study does not sca le these specific emissions nationally and we have not provided a separate scale up of those emis sions here.

19 **Id.**8

• **Stanford/Novim Analysis.** The Stanford/Novim analysis found that co-producin g well completions accounted for approximately 120,000 MT CH 4 in 2011. 20 The analysis assumed all emissions were vented and multiplied em issions factors in the Bakken, Eagle Ford, and Permian Basins by the total number of completions in those basins. Because the 120,000 MT CH 4 figure includes only emissions from these three ba sins, it is not a true national figure.

• **ICF Report**

. ICF used its emissions factor of 344,000 scf CH 4 /completion (6.6 MT
CH 4 /completion) from Subpart W along with the most rec ent API Quarterly Completions Report showing 15,382 hydraulically fractured oil w ell completions for 2011. Using these values, ICF calculated completion emissions of 5 Bc f CH 4 or 96,000 MT CH 4 .

• **EDF Subpart W Analysis**

. EDF applied emissions factors we calculated from Su bpart W to the 2012 Draft GHG Inventory activity data of 15 ,753 oil well completions. 21 This

r esulted in emission estimates between 49,000 MT CH 4 (assuming all RECs) and 343,000 MT CH 4 (assuming all emissions vented), or 182,000 MT CH 4 if the use of emission controls among the 15,753 oil well completions is a ssumed to be distributed in the same way as the Subpart W dataset. Because some wells a re already controlled, we assumed the national proportion of uncontrolled completions was 43%, the same as the Subpart W dataset, and applied the emission factor for vent ed completions. We use this 147,000 MT CH 4 value for purposes of determining mitigation poten tial.

• **EDF/Stratus Analysis**

. The EDF/Stratus analysis did not isolate hydraulica lly fractured wells, but instead derived an average emission fact or applicable to all co-producing well completions. Accordingly, EDF applied emissions fa ctors we calculated using the Stratus methodology to EPA’s 2012 Draft GHG Inventory activ ity data of 15,753 oil well completions for an emissions estimate of approximat ely 247,000 MT CH 4 annually.

Translating these national emissions estimates into mitigation potential requires applying control efficiencies. The ICF Report assu mes flaring achieves 98% DRE, and accordingly suggests mitigating completion emissions from co-pr oducing wells could achieve 94,000 MT CH 4 in annual reductions.

20 A.R. Brandt et al., Supplementary Materials for **Methane Leaks from North American Natural Gas Syste ms**  30, 343 S CIENCE 733 (Feb. 14, 2014), **available at** http://www.sciencemag.org/content/suppl/2014/02/12/ 343.6172.733.DC1/1247045.Brandt.SM.pdf

.

21 Although not all oil wells completions use hydraul ic fracturing, FracFocus, the national hydraulic fr acturing chemical registry managed by the Ground Water Prote ction Council and Interstate Oil and Gas Compact Commission, includes records from 12,056 oil wells that were hydraulically fractured in 2012. Reportin g to FracFocus is voluntary in many states, which implie s that the actual number of hydraulically fractured oil wells is higher than 12,056. Accordingly, we have used the draft inventory activity data as a reasonable proxy for the total number of hydraulically fractured oil well completi ons.9

The Stanford/Novim analysis does not calculate miti gation potential, and so, consistent with the two EDF analyses, we conservatively assume flaring or gas capture achieves a 95% control efficiency. Because both the Stanford/Novi m analysis and EDF/Stratus analysis assume all emissions are vented, we apply the 95% control figure directly to total emissions estimates, resulting in annual mitigation potentials of 114,00 0 MT CH 4 and 228,000 MT CH 4 respectively. Because EDF’s Subpart W analysis assumes some wells are already controlled, we apply the 95% control effectiveness only to the subset of emi ssions that are vented for an annual mitigation potential of 140,000 MT CH 4 .

Conclusions

Although neither EPA regulations nor the regulation s of most states require control of emissions from co-producing well completions, these emissions are a potentially significant source of methane and other harmful pollutants. Re cent studies and analyses – drawing from a variety of data sources including field studies of well completions, Subpart W reports, and well completion databases – suggest that emissions from an uncontrolled co-producing well completion range from 15.7 MT of CH 4 to nearly 200 MT. At a national level, these emis sion factors suggest total co-producing well completion emissions between approximately 96,000 to 247,000 MT, comparable to emissions from natural ga s well completions (209,000 MT CH 4 in the latest EPA annual inventory). Current control technologies for natural gas well completions – including RECs where gathering infrastructure is available, and high-efficiency flaring in other situations – can be readily applied to co-producing well completions. This white paper suggests that applying those technologies to co-producing we ll completions would yield emission reductions on the order of 94,000 to 228,000 MT per year, or 2.63 to 6.38 million MT CO 2 -e (using 100-year GWP of 28).