1 

CO-PRODUCING WELLS AS A MAJOR SOURCE OF METHANE EMISSIONS: 

A REVIEW OF RECENT ANALYSES

PREPARED BY ENVIRONMENTAL DEFENSE FUND 

MARCH 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 reduced 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 interpreted, a number of 

wells that co-produce oil (or other liquids) and natural gas (“co-producing wells”) may not need 

to control their emissions under the REC requirements in the NSPS. 

Many completions of these co-producing wells, however, produce substantial pollution 

that can be cost-effectively mitigated using the same 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, driven primarily by increases in tight oil 

production (see Figure 1). 

Figure 1. US Petroleum and Other Liquids Supply, 1970-2040 (EIA) 

 

1

 With limited exceptions, all fractured and refractured 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 using RECs or high-efficiency flaring, and, 

where possible, the total amount of methane that would be reduced by deploying these 

completion protections at co-producing wells. Table 1 synthesizes data from the following 

sources: 

• A February, 2014 Stanford/Novim Study in the journal Science entitled “Methane 

Leakage from North American Natural Gas Systems;” (“Stanford/Novim Analysis”)3

 

• ICF International’s Report from March, 2014 entitled “Economic Analysis of Methane 

Emissions Reduction Opportunities in the U.S. Onshore 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 of 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 completions are a substantial source of 

methane emissions, with total estimated emissions much larger than the figure reported in 

EPA’s official inventory of greenhouse gas emissions. EPA’s current emission factor for coproducing wells derives from a 1996 study of conventional oil wells, and very likely 

underestimates emissions from the hydraulic fracturing techniques that are prevalent today. 

 

3

 A.R. Brandt et al., Methane Leaks from North American Natural Gas Systems, 343 SCIENCE 733 (Feb. 14, 2014), 

available at http://www.novim.org/images/pdf/ScienceMethane.02.14.14.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 production 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. Greenhouse Gas Emissions and Sinks: 1990–2012” (included in the 

supplemental information for this analysis). 
3 

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

Data 

Sources 

Potential 

Emission 

Factor (MT 

CH4) 

National 

Emissions 

Estimates*** 

(MT CH4) 

REC Cost 

Effectiveness 

($/MT CH4) 

Flaring Cost 

Effectiveness 

($/MT CH4) 

Methane 

Mitigation 

Potential 

without (MT CH4) 

savings 

with 

savings 

Stanford/ 

Novim 

Analysis* 

40.27 120,000**** 778 92 114,000 

ICF Report 6.6** 96,000 n/a n/a 96.57 94,000 

UT Study * 193.5 153.8 -132.78 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 controlled emissions so is not a true potential 

emissions factor. 

*** Estimates provided by the authors of each individual study. 

**** This estimate only reflects emissions from three major production basins, and therefore 

understates total national emissions. 

 The remainder of this white paper provides additional information on the development 

of an emission factor for co-producing wells, the cost-effectiveness of mitigating these 

emissions, and overall methane mitigation potentials. 

Potential Emission Factor 

The above-described analyses determine potential emissions factors for co-producing 

well completions using several different methods, including 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 fractured wells, the more recent studies 

described below suggest that the official inventory is likely underestimating the extensive 

methane emissions from co-producing well completions. 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 completions, 

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 methane in the production 

sector, including 27 well completions in various geographic areas across the country. Six of the 

measured completions were at co-producing wells that produced significant amounts of 

hydrocarbon liquids,10 and, for each of these completions, researchers directly measured 

potential and actual methane emissions. Actual completion emissions from these co-producing 

wells ranged from 1.7 to 5.0 metric tons (“MT”) CH4, though all of the wells controlled 

completion flowback emissions with either flaring or a combination of RECs and flaring. The UT 

study estimated potential emissions as the total volume of gas vented, flared, and sent to sales 

from initiation of flowback until the reported completion end time. The potential emissions 

from these wells, which would be more indicative of uncontrolled completions, ranged from 

81.9 to 414.4 MT CH4, with an average value of 193.5 MT of CH4/completion.11 

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

Completion 

Event 

Emission 

Controls 

Measured 

Emissions 

(scf CH4) 

Potential 

Emissions 

(scf CH4) 

Measured 

Emissions 

(MT CH4) 

Potential 

Emissions 

(MT CH4) 

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 2012 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 wells 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 production 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 analysis). 

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

completions. 

12 EDF, Comments on “Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2012” (included in the 

supplemental information for this analysis). 
5 

emissions. Nonetheless, in 2011 and 2012 there were 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 these completion reports came, 

over half of the wells with first production in 2011 & 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 

CH4/event, or more than 400 times higher than the current oil well completion emission factor. 

EDF also developed separate emission factors for each combination of emission controls 

reported under Subpart W: uncontrolled (“vented”) completions, completions controlled with a 

flare, completions controlled with a REC, and completions controlled with both flares and REC. 

The emission factors for the four categories range from 3.1 MT CH4/event for completions with 

REC to 21.8 MT CH4/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 develops an emissions factor of 344,000 scf 

CH4/completion or 6.6 MT CH4/completion, which is an average value including both 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 

CH4/event) 

Workovers 

EF (MT 

CH4/event)

Completion 

& Workover 

EF (MT 

CH4/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 these 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 Systems, 343 SCIENCE 733 (Feb. 14, 2014), 

available at http://www.novim.org/images/pdf/ScienceMethane.02.14.14.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 rate. It then assumed that production during 

flowback increased linearly with time for 9 days prior to initial production and all such methane 

emissions were vented, or understood differently, that completion emissions correspond to 4.5 

days of initial gas production.15 Using this methodology, the analysis determined potential 

emissions factors for the Bakken (31.1 MT CH4/completion), Eagle Ford (90.9 MT 

CH4/completion), and Permian (31.2 MT CH4/completion) Basins. 

The EDF/Stratus analysis takes a similar approach, using initial production values to 

understand potential completion emissions at co-producing wells. Stratus Consulting initially 

performed an analysis of 100 well completions in the Bakken, assuming a 7 to 10 day 

completion event with gas production increasing from zero to the initial production value in a 

non-linear fashion over the course of the completion. Accordingly, Stratus assumed that total 

gas production over the 7-10 day completion event would equal 3 average days of gas 

production.16 As with the Stanford/Novim analysis, Stratus assumed all of this gas was vented. 

EDF subsequently extended this analysis to approximately 9,500 wells in the Bakken, 

Eagle Ford, and Wattenberg fields.17 Only oil wells were analyzed for the Eagle Ford and 

Wattenberg fields; North Dakota does not distinguish between oil and gas wells so all Bakken 

wells were assumed to be oil wells. Across all wells, the analysis found an average potential 

emissions factor of 15.7 MT CH4/completions with averages of 18.0, 24.7, and 9.5 MT 

CH4/completion in the Bakken, Eagle Ford, and Wattenberg respectively. 

Cost Effectiveness 

Other than the ICF Report, none of the above non-EDF analyses calculated the costeffectiveness of controlling completion emissions using 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 efficiency and used EPA’s cost of performing a 

reduced emission completion ($29,713)18 to calculate cost-effectiveness. Across all studies, we 

calculated a REC cost-effectiveness without a credit for captured gas ranging from $154 - 

$3,578/MT CH4 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’Sullivan & Sergey Paltsev, Shale gas production: potential versus actual 

greenhouse gas emissions, ENVTL. RES. LETTERS 7(4):044030 (Nov. 26, 2012). 

16 Memorandum from Leland Deck, Stratus Consulting, to Peter Zalzal and Vickie Patton, Environmental Defense 

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 Performance for Crude Oil and Natural Gas Production, 

Transmission, and Distribution, Background Technical Support Document for Proposed Standards (July 2011), 

available at http://www.epa.gov/airquality/oilandgas/pdfs/20110728tsd.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 CH4 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 Median 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 emission factor to get flaring emission reductions. 

We then divided the EPA cost estimate of flaring completion emissions from a well ($3,523) by 

the flaring emission reductions for each of the analyses.19 Across all studies (excluding the ICF 

Report) we calculated a flaring cost-effectiveness ranging from $19 - $424/MT CH4 reduced. 

The ICF Report includes its own cost assumptions about 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 $50,000, 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 CH4) for completion gas. The ICF report did not examine the cost-effectiveness of 

RECs for co-producing wells.

Mitigation Potential 

 Determining inventory-wide mitigation potential requires scaling up emissions 

nationally and then applying percentage reductions associated with mitigation technologies. 

The Stanford/Novim Analysis, the ICF Report, the EDF Subpart W Analysis, and the EDF/Stratus 

Analysis all provide national estimates of emissions from co-producing wells, which we describe 

in greater detail below. The UT Study does not scale these specific emissions nationally and we 

have not provided a separate scale up of those emissions here. 

 

19 Id. 
8 

• Stanford/Novim Analysis. The Stanford/Novim analysis found that co-producing well 

completions accounted for approximately 120,000 MT CH4 in 2011.20 The analysis 

assumed all emissions were vented and multiplied emissions factors in the Bakken, 

Eagle Ford, and Permian Basins by the total number of completions in those basins. 

Because the 120,000 MT CH4 figure includes only emissions from these three basins, it is 

not a true national figure.

• ICF Report. ICF used its emissions factor of 344,000 scf CH4/completion (6.6 MT 

CH4/completion) from Subpart W along with the most recent API Quarterly Completions 

Report showing 15,382 hydraulically fractured oil well completions for 2011. Using these 

values, ICF calculated completion emissions of 5 Bcf CH4 or 96,000 MT CH4. 

• EDF Subpart W Analysis. EDF applied emissions factors we calculated from Subpart W 

to the 2012 Draft GHG Inventory activity data of 15,753 oil well completions.21 This

resulted in emission estimates between 49,000 MT CH4 (assuming all RECs) and 343,000 

MT CH4 (assuming all emissions vented), or 182,000 MT CH4 if the use of emission 

controls among the 15,753 oil well completions is assumed to be distributed in the same 

way as the Subpart W dataset. Because some wells are 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 vented completions. We use this 147,000 

MT CH4 value for purposes of determining mitigation potential. 

• EDF/Stratus Analysis. The EDF/Stratus analysis did not isolate hydraulically fractured 

wells, but instead derived an average emission factor applicable to all co-producing well 

completions. Accordingly, EDF applied emissions factors we calculated using the Stratus 

methodology to EPA’s 2012 Draft GHG Inventory activity data of 15,753 oil well 

completions for an emissions estimate of approximately 247,000 MT CH4 annually. 

Translating these national emissions estimates into mitigation potential requires 

applying control efficiencies. The ICF Report assumes flaring achieves 98% DRE, and accordingly 

suggests mitigating completion emissions from co-producing wells could achieve 94,000 MT 

CH4 in annual reductions. 

 

20 A.R. Brandt et al., Supplementary Materials for Methane Leaks from North American Natural Gas Systems 30, 

343 SCIENCE 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 hydraulic fracturing, FracFocus, the national hydraulic fracturing 

chemical registry managed by the Ground Water Protection Council and Interstate Oil and Gas Compact 

Commission, includes records from 12,056 oil wells that were hydraulically fractured in 2012. Reporting to 

FracFocus is voluntary in many states, which implies 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 completions. 
9 

The Stanford/Novim analysis does not calculate mitigation 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/Novim 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 114,000 MT CH4 and 228,000 MT CH4 respectively. 

Because EDF’s Subpart W analysis assumes some wells are already controlled, we apply the 

95% control effectiveness only to the subset of emissions that are vented for an annual 

mitigation potential of 140,000 MT CH4. 

Conclusions 

Although neither EPA regulations nor the regulations 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. Recent 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 CH4 to nearly 200 MT. At a national level, these emission 

factors suggest total co-producing well completion emissions between approximately 96,000 to 

247,000 MT, comparable to emissions from natural gas well completions (209,000 MT CH4 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 well 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 CO2-e 

(using 100-year GWP of 28).