Attachment D

Hydraulically Fractured Oil Wells

Environmental Defense Fund

Ramón Alvarez, Robert Harriss, David Lyon
Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions 

and Associated Gas during Ongoing Production 

Peer Review Responses of Environmental Defense Fund

June 16, 2014 

I. EXECUTIVE SUMMARY

• Oil well completions and associated gas venting are a significant source of methane 

and VOC emissions. Emissions from both hydraulically fractured oil well completions 

and associated gas venting are significant and, absent controls, likely to increase in the 

future as swift development is projected to occur in oil-rich formations. 

o Completion emissions factor. The best available data suggest that uncontrolled oil 

well completion emissions range from 7.7 to 213 tons CH4 per event, substantially 

higher than the EPA inventory estimate of 0.0156 tons CH4 per event. Using 

conversion factors based on data from the UT Production Study, VOC emissions 

from oil well completions likely range from 3.7 to 101.8 tons — higher than VOC 

emissions from gas well completions. Data from the UT Production Study also 

helps to validate the method of using initial production values to estimate 

uncontrolled completion emissions. 

o National oil well completion emissions. National emissions estimates are 

significant, ranging from 44,000 – 272,000 tons CH4. The lower values, however, 

assume only horizontal wells are hydraulically fractured and so likely 

substantially understate emissions. 

o Associated gas emissions. Onshore oil and gas production companies reported

over 98,000 tons of associated gas venting and flaring methane emissions in 2012. 

The majority of venting and flaring emissions occur in a few basins: 64% of 

venting emissions are from the Permian and East Texas basins and 75% of flaring 

emissions are from the Williston basin. 

• Control technologies are available that can cost-effectively reduce completion 

emissions and associated gas emissions.

o Oil well completion control technologies. The same technologies available to 

reduce emissions at gas wells can cost-effectively mitigate oil well completions. 

The UT Production Study demonstrates that both Reduced Emission Completions 

(“RECs”) and flaring are feasible at hydraulically fractured oil wells. RECs are 

far preferable because they capture gas that would otherwise be wasted, and 

accordingly, can significantly offset the costs associated with reducing emissions. 

o Access to infrastructure. Infrastructure to support gas capture is swiftly expanding 

in many oil producing areas, which can support capture of both completion 

emissions and associated gas. Emissions can also be reduced using alternatives 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

2 

such as on-site power generation. Lastly, flaring is broadly available and costeffective, but should be used only as a control measure of last resort.

II. QUANTIFYING THE PROBLEM OF METHANE & VOC LEAKS FROM OIL 

WELL COMPLETIONS AND ASSOCIATED GAS PRODUCTION (QUESTIONS 1, 2, 4, 5,

6, 10, 12)

EPA’s Hydraulically Fractured Oil Wells Paper (“Oil Well Paper”) presents information 

on per-event emissions from hydraulically fractured oil well completions and estimates of total 

national emissions from these events. Similarly, for associated gas venting, the Oil Well Paper 

describes potential methodologies to derive per-well emissions and provides some data on 

national emissions. Each one of these emissions estimates is important for different reasons. 

Per-event emissions factors are critical to understand the effectiveness of mitigation technologies 

and evaluate costs associated with those technologies. They also establish a foundation for 

estimating national emissions, which are, in turn, essential for understanding the cumulative 

importance of a particular source category and impact of applying a certain control strategy. 

Part II.A addresses different aspects of these per-event emissions estimates and evaluates 

national estimates of emissions from hydraulically fractured oil well completions, with particular 

emphasis on the dated activity factors included in the Oil Well Paper, which result in 

underestimates of national emissions. Part II.B discusses EPA’s evaluation of associated gas 

emissions and Part II.C concludes. 

We conclude: 

• The best available data suggest that uncontrolled oil well completion emissions range 

from 7.7 to 213 tons CH4 per event, substantially higher than the EPA inventory estimate 

of 0.0156 tons CH4 per event. Using conversion factors based on data from the UT 

Production Study, VOC emissions from oil well completions likely range from 3.7 to 

101.8 tons — higher than VOC emissions from gas well completions. Data from the UT 

Production Study also helps to validate the method of using initial production values to 

estimate completion emissions. 

• National oil well completion emissions. National emissions estimates are significant, 

ranging from 44,000 – 272,000 tons CH4, though the lower end of this range uses activity 

factors that we do not believe are accurate and so likely substantially understates 

emissions. 

• Associated gas emissions. Onshore oil and gas production companies reported over 

98,000 tons of associated gas venting and flaring methane emissions in 2012. The 

majority of venting and flaring emissions occur in a few basins: 64% of venting 

emissions are from the Permian and East Texas basins and 75% of flaring emissions are 

from the Williston basin. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

3 

• Emissions will likely increase in the future as EIA projects that over half of new wells 

will co-produce natural gas—leading to a substantial increase in completion emissions.1

A. Hydraulically Fractured Oil Well Completions Emissions 

Below, we briefly address the definition of “oil wells.” We then analyze the different 

emissions factors EPA presents, present an alternative methodology for estimating emissions 

using Greenhouse Gas Reporting Program Subpart W, and finally discuss national emissions 

from this source category. 

1. Defining oil wells 

A clear definition of oil wells is helpful for understanding oil well emissions, though, as 

we discuss in Part III, below, not necessary for evaluating control technology (which are equally 

applicable to oil and gas well emissions). The Oil Well Paper points to several definitions of oil 

wells, including NSPS OOOO and Subpart W. In particular, the NSPS defines a gas well as “an 

onshore well drilled principally for production of natural gas” and EPA has just proposed to 

revise the definition in Subpart W, which is based on sub-basin formation type and other 

attributes. 

 Gas-to-oil ratio (GOR) may further help to distinguish oil and gas wells. EDF analyzed 

DI Desktop production data for 11,329 gas wells and 13,306 oil wells with first production in 

2012. The well type definitions in DI Desktop are based on state regulatory definitions and thus 

vary from state to state. The average GOR of gas wells based on the first year production was 

5,270,044 scf/bbl, compared to 3,840 scf/bbl for oil wells. The percentage of wells with GOR 

greater than 12,500 scf/bbl (the threshold identified in the Oil Wells Paper) was 89.3% for gas 

wells and 4.7% for oil wells. 

Although we are not specifically advocating for defining oil wells based on a GOR less 

than 12,500 scf/bbl, we do recommend EPA clarify that hydraulically oil wells that co-producing 

natural gas also be required to reduce emissions, similar to the approach Colorado takes which 

does not distinguish between oil and natural gas well completions. Ultimately, we emphasize 

that defining “oil wells” helps to understand national emissions from this source category, but it 

is not critical for determining that pollution control technology can effectively mitigate these 

emissions. 

 

1

 EIA, Drilling often results in both oil and natural gas production (Oct. 2013), available at

http://www.eia.gov/todayinenergy/detail.cfm?id=13571. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

4 

2. Evaluating Per-Event Oil Well Completion Estimates (Questions 1, 4) 

The Oil Wells Paper includes emission estimates based on two types of data – direct 

measurements and production data. The average uncontrolled methane emissions per completion 

estimated from these data sources range from 7.7 to 213 tons with an overall average of 50.6 

tons. Although the range of these estimates is large, they are all much higher than the oil well 

completion emission factor of 0.0156 tons per completion currently used in the GHG Inventory. 

The UT Study (Allen et al., 2013) includes direct measurements of hydraulically 

fractured oil well completions, including six such wells in the Gulf Coast region (out of 27 total 

wells measured). The average potential emissions, which include methane sent to the flare or 

sales, were 213 tons. All of these wells controlled emissions with either flares or reduced 

emission completions (REC), and so average actual emissions were 3.2 tons, indicating 98.5% 

control efficiency. 

The UT study reported additional data which helps to establish a relationship between 

uncontrolled emissions and initial production. In particular, the well operators reported the 

average daily gas production for the 30 days following the completion, which can be compared 

to potential completion emissions. For the six hydraulically fractured oil wells, potential 

completion emissions ranged from 2.0 to 20.1 days of average daily gas production with an 

overall average of 5.0 days (assuming a gas composition of 78.8% methane). The average 

completion duration of these wells was 3.3 days, which indicates that completion flowback 

emission rates can exceed the average rate of production over the well's first month. 

The other data sources evaluated by EPA (EC/R; EDF/Stratus; Brandt et al., 2014) 

estimated uncontrolled completion emissions based on analyses of gas production data and 

assumptions about the relationship between production data and completion emissions. Though 

similar, individual results varied based on assumptions about completion duration and the time 

period and type of production data used. 

Production Data. The EC/R analysis found the lowest emission factor, though it likely 

underestimates emissions based on the production data it uses. In particular, EC/R calculated 

average daily production based on first-year’s production. Gas production typically declines over 

time – an EDF analysis of DI Desktop production data from 15,962 oil wells with first 

production in 2012 determined that average daily production during the first year is 72% of 

practical initial production (DI Desktop bases practical initial production on the 2nd month of 

production to represent a full month of production). The UT Study data indicates that completion 

flowback emissions can exceed the first month's average production rate; therefore, use of the 

lower average daily production during the first year would underestimate emissions substantially. 

Completion duration. Assumptions about completion duration ranged from 3 to 9 days, 

with some analyses supposing constant emissions and others linearly increasing emissions. The 

UT Study Appendix H include figures of completion flowback emission rates over time – the 27 

completion flowbacks emission rates are highly dynamic and variable, which demonstrates the 

assumption of constant or linearly increasing emissions is rarely true. However, the critical 

parameter for estimating emissions is the equivalent days of production, not the change of 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

5 

emission rates during the completion. The UT Study co-producing wells had potential emissions 

equivalent to 5.0 days of average first 30 day production, higher than the equivalent days used in 

all the analyses except the EC/R analysis, which used a 7 day flowback period with a constant 

rate (though, as discussed above, the EC/R analysis used an average daily gas production rate 

based on first-years production, which substantially underestimates emissions). 

Although the UT Study data is limited for hydraulically fractured oil wells, the 

relationship it helps to establish between initial production and completion emissions can be used 

to estimate uncontrolled emissions. Assuming potential emissions are equivalent to 5 of days of 

initial first 30 day production and that produced flowback gas is 78.8% methane, the average 

potential completion emissions of the 15,962 oil wells with first production in 2012 are 28.1 tons 

per completion. Additional direct measurement data would be valuable for sharpening existing 

emission factors, but it is clear that uncontrolled oil well completion emissions per well are much 

closer to the GHG Inventory emission factor for hydraulically fractured gas wells that vent (45.2 

tons/completion) than the oil well completions (0.0156 tons/completion). 

Finally, we note that oil wells typically have a greater percentage of VOCs than gas 

wells, a relationship that the data from the UT study helps to substantiate. Using a conversion 

factor of 0.478 lbs VOC / lbs CH4, based on gas composition data from 18 sites in the UT 

Production Study with a GOR less than 12,500 scf/bbl,2 VOC emissions from oil well 

completions likely range from 3.7 to 101.8 tons — higher than VOC emissions from gas well 

completions. 

3. Other Methodologies for Estimating Oil Well Completion Emissions 

(Question 3) 

EPA’s Greenhouse Gas Reporting Program Subpart W for petroleum and natural gas 

systems requires reporting of emissions from gas well completions and workovers, but not oil 

well completions and workovers. Nonetheless, in 2011 and 2012 there were 1,754 reports of 

completions and workovers from wells in sub-basins 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. In approximately 75% of the counties from which these completion 

reports came, over half of the wells with first production in 2011 and 2012 were oil wells. This 

supports the conclusion that some operators have voluntarily submitted emissions data from oil 

well completions and workovers. 

For the 2014 US GHG Inventory, EPA used 2011 and 2012 Subpart W data to develop 

emission factors for gas well completions and workovers. Using the same method as EPA, EDF 

has developed emission factors based on the subset of 2011 and 2012 Subpart W data from wells 

completions and workovers in oil formation sub-basins (Table 1). The average emission factor 

for all oil formation completions and workovers is 6.2 metric tons CH4 per event, or more than 

400 times higher than the current oil well completion emission factor. EDF also developed 

 

2

 David T. Allen et al., Measurements of methane emissions at natural gas production sites in the United States, 

PNAS Early Edition (2013)[hereinafter “UT Study”], available at http://www.pnas.org/cgi/doi/10.1073/ 

pnas.1304880110. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

6 

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 per completion for completions with REC to 21.8 MT 

CH4 per completion for vented completions.3

Table 1. Oil well completion and workover emission factors developed from 2011 & 2012 

GHGRP Subpart W oil formation type sub-basins. 

Category Completions 

(# events) 

Workovers 

(# events) 

Completions 

& 

Workovers 

(# events) 

Completions 

(Mg CH4 / 

event) 

Workovers 

(Mg CH4 / 

event) 

Completions 

& 

Workovers 

(Mg 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 

4. Evaluating National Emissions Estimates (Question 1) 

National emissions estimates typically are based on emission factors and activity factors 

and also are influenced by the prevalence and efficiency of control technologies. The Oil Wells 

Paper presents national emission estimates ranging from 44,306 to 272,000 tons per year. As 

discussed above, the data reflect a range of emission factors (all substantial) and there is ample 

data supporting the use of an uncontrolled emission factor of a similar magnitude as the emission 

factor for hydraulically fractured gas wells that vent. In this section, we focus on evaluating 

activity factors and how they impact national estimate, including the number of newly fractured 

oil wells; the number of recompleted oil well; and the prevalence of control technologies. 

Newly Fractured Oil Wells. There are at least two databases that can be used to estimate 

the number of hydraulically fractured oil wells. DrillingInfo maintains the production database 

DI Desktop, which includes data compiled from state oil and gas regulatory agencies. DI 

Desktop does not currently include data indicating if a well was hydraulically fractured, but it 

does include information such as the formation and drill type (horizontal, vertical, directional) 

that can be used to predict if a well was hydraulically fractured. The EC/R analysis estimated the 

number of hydraulically fractured oil well completions in 2011 was 6,169 by identifying 

horizontal wells with first production in 2011 that produce from coal bed methane, tight, or shale 

formations. As discussed below, we believe their method underestimates hydraulically fractured 

completions significantly. 

 

3

 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 per completion or 6.6 MT CH4 per

completion, which is an average value including both controlled and uncontrolled completions. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

7 

FracFocus, a chemical disclosure registry managed by the Ground Water Protection 

Council and Interstate Oil and Gas Compact Commission, includes well production type of the 

reported hydraulically fractured wells. The FracFocus website does not currently allow bulk data 

downloads, but the organization SkyTruth has compiled 2011 and 2012 data for public use. The 

compiled FracFocus data includes records from 12,056 oil wells with hydraulic fracturing dates 

in 2012. Although reporting to FracFocus is mandatory in several states, it is voluntary in others 

and therefore the actual number of completions is likely higher than the number reported. 

In comparison, DI Desktop includes 6,225 horizontal oil and oil & gas wells with first 

production in 2012 (North Dakota and Pennsylvania do not distinguish between oil and gas 

wells, thus some of the 2,003 horizontal oil & gas wells may actually be gas wells). Applying 

the EC/R approach would further decrease this number by filtering by formation type; therefore, 

it is evident that this method underestimates oil well completions compared to FracFocus. DI 

Desktop also includes 13,001 directional, vertical, and unknown drill type oil and oil & gas wells 

with first production in 2012. Clearly, hydraulic fracturing and completions are occurring in 

significant fraction of vertical and directional oil wells. The 2012 GHG Inventory uses an 

activity factor of 15,753 oil well completions based on the Energy Information Administration 

Monthly Energy Review. Assuming both the EIA and FracFocus values are accurate, at least 

76.5% of oil wells are hydraulically fractured. This is similar to an 80% hydraulic fracturing rate 

for oil wells estimated by industry experts. 

The Oil Wells Paper states that the EDF/Stratus analysis did not explain how the estimate 

of 2012 uncontrolled oil well completion emissions of 247,000 metric tons (272,000 short tons) 

was calculated. The analysis uses the average uncontrolled emission factor of the EDF/Stratus 

analysis of production data from 9,458 oil wells in the Wattenberg, Bakken, and Eagle Ford 

formations. This emission factor, 15.7 metric tons per completion, was multiplied by the EPA 

oil well completion activity factor of 15,753 completions. This activity factor may be 

conservatively high since it is based on the assumption that all oil wells are hydraulically 

fractured (though we note the emissions factor we use is lower than most). Using the FracFocus 

activity data of 12,056 completions, the estimate would be reduced to 189,279 metric tons 

(208,644 short tons). 

Recompleted Oil Wells (Question 6). As indicated in the white paper, there is uncertainty 

about the rate of recompletions of hydraulically-fractured oil wells. A likely reason for the lack 

of data is the relatively young age of most unconventional oil wells. As the population of wells 

ages, the recompletion rate should increase. Continuing to analyze Colorado, Texas, and 

Wyoming databases and other information sources as new data becomes available will help to 

refine the recompletion rate. 

Prevalence of control technologies (Question 10). The UT Study indicates that oil well 

completions can use REC or flaring to reduce emissions by 98.5%, but the sample size is too 

small to estimate the fraction of wells that currently use these controls. There is some 

information available from the Subpart W data of gas well completions and workovers in oil 

formation sub-basins. As stated previously, we believe much of the data are from voluntarily 

reported oil well completions. Using the same method as EPA to estimate the number of 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

8 

uncontrolled (“vented”) completions, completions controlled with a flare, completions controlled 

with a REC, and completions controlled with both flares and REC for the 2012 GHG Inventory, 

we estimated the distribution of controls for the subset of completions from oil formation subbasins. The method was able to unambiguously classify 744 of completion events into control 

categories. Control technologies were used by 57% of the wells: 30% flaring, 25% REC, and 

2% REC and flaring. Applying the same distribution to the 2012 GHG Inventory of 15,753 oil 

well completions, we estimated national emissions using the four completion emission factors 

we developed from the Subpart W oil formation data. The estimated net emissions are 182,000 

metric tons (200,200 short tons), which is over 800 times greater than the current GHG Inventory 

estimate of 222 metric tons. 

While current national emissions are significant, as we discuss above, these emissions are 

likely to increase given the swift pace of development in regions that co-produce oil and natural 

gas. 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). 

B. Evaluating Associated Gas Emissions Estimates 

In addition to oil well completion emissions, EPA’s White Paper evaluates associated gas 

emissions (natural gas co-produced with oil during ongoing production). GHG Reporting 

Program Subpart W requires reporting of emissions from associated gas venting and flaring from 

onshore petroleum & natural gas systems for facilities exceeding the reporting threshold of 

25,000 metric tons CO2e. Emissions are reported at the facility level, which is defined as a 

company’s entire production operations in a basin. In 2012, facilities reported 11,144 venting 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

9 

wells and 6,901 flaring wells with 59,528 and 30,007 metric tons of methane emissions from 

venting and flaring, respectively, for a total of 89,535 metric tons (98,695 short tons). 

There are large differences among basins in the number of venting and flaring wells and 

their emissions. For venting wells, the Permian and East Texas basin comprised 48% of the wells 

and 64% of the emissions. There are very large differences between the average emissions of the 

two basins – the Permian Basin had 5,350 venting wells with an average of 4.3 metric tons per 

well, while the East Texas Basin had 20 venting wells with an average of 734.4 metric tons per 

well. For flaring wells, the Williston Basin and Gulf Coast Basin comprised 68% of the wells 

and 89% of the emissions, but with similar average emission rates of 5.6 and 5.8 metric tons per 

well, respectively. The Williston Basin in particular had high rates of flaring, contributing 75% 

of total emissions. Overall, the average methane emissions were 5.3 metric tons per venting well 

and 4.3 metric tons per flaring well. 

The North Dakota Industrial Commission requires reporting of gas flared per well on a 

monthly basis. In 2012, the state reported 83.5 Bcf of flared gas, or 32% of produced gas. If 

flared gas is assumed to have 78.8% methane content and be controlled at 98% control 

efficiency, then reporting flaring would have emitting 25,269 metric tons methane emissions, 

similar to the 23,922 metric tons reported to Subpart W. The close agreement is a favorable 

indication of the accuracy of the Subpart W estimates, but the North Dakota reporting 

requirements may result in higher accuracy compared to other basins. 

Additionally, uncertainty about flare control efficiency decreases the accuracy of the 

flaring methane emissions. Subpart W requires use of the flare manufacturer’s reported 

combustion efficiency or 98% if unavailable. Emissions could be higher if equipment 

malfunctions decrease the control efficiency. Furthermore, Subpart W estimates do not include 

emissions from facilities below the reporting threshold and therefore underestimate national 

emissions. This underestimate could be substantial if operators below the reporting threshold 

have higher average rates of venting and flaring. 

Finally, we note EPA’s discussion focuses on associated gas but urge the agency also to 

consider casinghead gas, which is also related to oil production but is emitted before natural gas 

flows through a separator. EPA should ensure that both casinghead gas emissions and mitigation 

technologies are examined, and as we discuss below, control technologies are available that 

specifically address casinghead emissions. 

III. UNDERSTANDING THE LANDSCAPE OF MITIGATION TECHNOLOGY,

EFFECTIVENESS, AND COST (QUESTIONS 7, 8, 9, 12, 13) 

EPA’s White Papers similarly address mitigation technologies applicable to both 

hydraulically fractured oil well completion emissions and associated gas venting, including the 

effectiveness and cost of these technologies. EPA focuses on reduced emission completions 

(“RECs”) and completion combustion or flaring, and we comment on the feasibility, cost, 

effectiveness, and prevalence of these devices in Part III.A. In Part III.B, we address EPA’s 

analysis of alternative technologies capable of reducing emissions from these sources. For 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

10 

reference, we discuss the prevalence of these control technologies in our discussion of national 

emissions estimates, in Part II above. 

We conclude: 

• The same technologies available to reduce emissions at gas wells can cost-effectively 

mitigate oil well completions. The UT Production Study demonstrates that both Reduced 

Emission Completions (“RECs”) and flaring are feasible at hydraulically fractured oil 

wells. RECs are far preferable because they capture gas that would otherwise be wasted, 

and accordingly, can significantly offset the costs associated with reducing emissions. 

• Infrastructure to support gas capture is swiftly expanding in many oil producing areas, 

which can support capture of both completion emissions and associated gas. Emissions 

can also be reduced using alternatives such as on-site power generation. 

• Flaring is broadly available and cost-effective, but should be used only as a control 

measure of last resort. 

 

A. Assessment of RECs / Flaring (Questions 7, 8, 9, 10) 

In this subsection, we focus on RECs and address EPA’s questions on feasibility (#7), 

effectiveness (#8), cost (#9), and prevalence (#10). We address these same issues concerning 

completion combustion in subsection B. 

1. Feasibility of RECs and Flaring at Hydraulically Fractured Oil Wells 

(Questions 7, 13) 

As we describe above, the distinction between an oil and gas well is artificial, and a 

completion operation at either can involve separation of natural gas from liquid hydrocarbons 

and water. Completion flowbacks may contain different percentages of oil, gas, and water, but 

this has little impact on the feasibility of technologies capable of controlling emissions at these 

sources. As EPA’s White Paper notes, this conceptual understanding is supported by data from 

the UT Production study, which definitively confirms that RECs and flaring are feasible (and 

have been done) at hydraulically fractured oil wells.

4

 Four of these wells controlled completion 

flowback emissions with flaring, and two of the wells utilized a combination of RECs and 

flaring. 

In addition, the Oil Wells Paper requests comment on the feasibility of deploying these 

technologies at hydraulically fractured oil wells, specifically with reference to certain well 

characteristics like well pressure, gas content of the flowback, gas to oil ratio, and access to 

infrastructure. In the UT Production Study Appendices, there are data concerning several of 

these variables. Our presentation of these data is not meant to suggest that they define the limits 

of what is feasible at an oil well, but instead that they provide evidence that RECs and flaring 

 

4

 White Paper at YY. 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

11 

have been successfully performed at wells with these characteristics. Table 2, below, 

summarizes these characteristics. 

Table 2: Summary of Well Characteristics at Hydraulically Fractured Oil 

Producing Wells Measured in UT Study.5

Completion Well Pressure 

(PSIG) 

Gas Content of 

Flowback (% 

methane)* 

Gas-Oil Ratio 

GC-1 443-545 psig 79.5 mol% 

methane 

4,046.36 

GC-2 500-525 psig 79.2 mol% 

methane 

4,266.82 

GC-3 189 - 1991 psig 

(mean 985; median 

1185) 

74 mol% methane 11,007.52 

GC-4 226 - 1284 psig 

(mean 991; median 

1184) 

48 mol% methane 

(increasing from 

35-60% during 

flaring) 

14,478.60 

GC-6 100 psig 88.3 mol% 

methane 

30,703.13 

GC-7 600-1100 psig 79.7 mol% 

methane 

3,508.10 

* Gas composition varies substantially over the course of the completion. These values were 

measured during the period when completion emissions were sent to a control device or to sales. 

• Access to Infrastructure. Access to infrastructure has no bearing on whether 

emissions can be controlled, but instead is important to understanding how they 

can be controlled – through capture or flaring. Infrastructure is also currently 

being built out in many regions co-producing gas and oil, and in other gas fields 

infrastructure is not an issue. Moreover, data from an October 2013 report from 

the North Dakota Pipeline Commission showed that 55% all flaring in the state 

occurred at wells connected to gathering infrastructure.6

• Well Pressure. Well pressure likely has some bearing on whether flowback 

emissions can be controlled – as EPA has recognized in the gas well context7

 – 

but several of the wells measured here controlled emissions despite having 

average well pressures lower than the 500 psig EPA highlights in its charge 

question. In addition, well pressure fluctuates over time during a completion and 

all but two of the completions (GC-2 and GC-7) controlled emissions at well 

pressures below 500 psig during some period of the flowback. 

 

5

 UT Study Appendices at 49-99.

6

 NDPC, North Dakota Natural Gas: A Detailed Look at Natural Gas Gathering (Oct. 2013), available at

http://ndpipelines.files.wordpress. com/2012/07/ndpa-detailed-look-at-gas-gathering-2013.pdf. 

7

 EPA, Technical Support Document for NSPS Subpart OOOO (2012). 
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

12 

• Methane Concentration. The data also show that methane concentration also 

fluctuates over time. The table, above, presents average methane concentration 

data from the period during which gas was sent to sales or flared, showing that 

gas streams with methane content as little as 35% were susceptible to flaring. 

Methane concentrations during initial flowback period also fluctuated, with some 

measurements as high as 77% (at GC-1)8 to negligible at other sites. 

• GOR. There is no discernable relationship in the UT dataset between GOR and 

the feasibility of performing a REC or flaring. Perhaps for wells with very low 

GORs – substantially below those measured in the UT study – there would not be 

sufficient gas produced to capture or operate a flare. That was not the case, 

however, in the UT Study and the study does not contain data to support that 

conclusion. GOR does, of course, impact the cost of performing a REC on 

account of the monetary savings due to captured gas. 

More importantly, the data underscore that, beyond access to infrastructure, reduced 

emissions completions and flaring are equally feasible at gas wells and oil wells. This 

conclusion is reinforced by the fact that states like Colorado require reduced emissions 

completions for oil and gas wells, without distinction, and instead focus on pressure 

characteristics as the determinant of completion feasibility.9

 

2. Costs of RECs and Flaring at Hydraulically Fractured Oil Wells 

(Question 8) 

EPA has likewise requested comment on the costs of RECs and flaring at hydraulically 

fractured oil wells, and we agree that the costs EPA’s White Paper presents are reasonable, and 

in some cases, conservative. 

RECs. EPA’s White Paper presents lower-bound costs associated with RECs of $700 per 

day (assuming key pieces of equipment are on site) and an upper-bound of $6,500 per-day 

(assuming key equipment must be brought in) for an average of $4,146 per-day. We note that 

average oil well completion durations from the UT Study were closer to three days (as opposed 

to the seven-day period EPA assumes in the TSD for NSPS OOOO). Using EPA’s average, perday value for the cost of performing a REC, total costs at these wells would be just over $12,000. 

Finally, we recognize that EPA’s costs are based on 2008 data, and RECs have become 

significantly more prevalent in the interim. Accordingly, newer data may show that cots have 

declined for performing these operations. 

These estimated costs will also be offset by cost recovery associated with gas capture. 

For the emissions factors presented from the UT study, monetary savings resulting from gas 

recovery taking place over the duration of the completion average $25,630, assuming the 

recovered gas sells at $4/Mcf. As EPA recognizes in the white paper, the extent of cost 

 

8

 Page 50 of Appendices.

9

 Co. Dep’t of Pub. Health & Env’t Reg. No. 7 (5 CCR 1001-9), Unofficial Draft (Feb. 23, 2014).
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

13 

mitigation available would depend on the market price of the gas and the percentage of gas 

recovered during a REC. 

Flares. The White Paper also presents costs for completion combustion devices or flares, 

citing an average cost figure for enclosed combustors of $18,092. In addition to the EPA has 

previously estimated the cost of flaring completions emissions to be $3,523 per well.10 

Moreover, the ICF Report contains different cost assumptions about performing high-efficiency 

flaring, which are substantially higher than all other estimates: initial capital cost of $50,000, 

with an additional $6,000 in fuel costs for ignition. 

In all of these figures, annual costs are conservatively assumed to be equal to the capital 

costs. The resulting costs therefore do not take into account the fact that completion combustion 

devices are deployed to control emissions from a number of wells, and we agree with EPA’s 

conclusion that such an approach grossly overstates cost and we urge the agency to adjust these 

assumptions to reflect real-world usage and conditions. 

3. Emissions Reductions Associated with RECs and Flaring at 

Hydraulically Fractured Oil Wells (Question 9) 

In the white paper, EPA estimated a representative control efficiency of 90% for RECs, 

noting that emissions reductions resulting from using a REC may vary depending on reservoir 

characteristics and other factors, including length of completion, number a of fractured zones, 

pressure, gas composition, and fracturing technology or technique. EPA also noted that any gas 

not recovered can be routed to a completion combustion device to achieve a minimum 95% 

reduction in emissions. 

The UT study found that “for those wells with methane capture or control, 99% of the 

potential emissions were captured or controlled,” and both of the wells that co-produced oil and 

gas and were controlled through a REC reported a greater than 98% reduction in methane 

emissions. Though we recognize that these factors can influence control effectiveness, it is 

likewise important to emphasize that equipment configuration can improve effectiveness. For 

instance, two co-producing wells analyzed in the UT study utilized an equipment configuration 

consisting of: (1) a gas-buster tank for initial flowback, (2) a separator that sent gas to sales or a

flare, and (3) a flowback tank for hydrocarbon liquids that vented to a combustion device, 

helping to minimize venting during the initial stages of the flowback operation. 

For flaring, EPA estimated an average control efficiency of 95% over the duration of a 

completion or recompletion. This figure incorporates assumptions, including that the combustion 

device has a continuous ignition source and an external fuel supply. Other factors, such as 

weather, will also affect the efficiency of completion combustion devices. The UT study, on the 

other hand, assumed 98% control efficiency. Both of these numbers likely overstate the 

effectiveness of flaring, particularly in dispersed field environments where it is more difficult to 

 

10 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.
ENVIRONMENTAL DEFENSE FUND • JUNE 16, 2014 

14 

control the conditions (like weather) that might lead to a flare going out. For this reason, we 

believe that RECs are preferable as a more rigorous control option when infrastructure is present. 

B. Alternative Control Technologies 

Additional control technologies may also be viable as an alternative to flaring associated 

gas. However, none of these technologies, standing alone, will likely completely address the 

problem of flaring gas from oil production. 

Several existing alternative control technologies may be deployed in different contexts 

and have shown varying levels of effectiveness. Natural gas may be used to produce electricity 

at or near a well using a gas turbine generator, which could provide power for the grid or onsite 

use. Natural gas can also be used as a substitute for diesel fuel in drilling or hydraulic fracturing

engines. Finally, vapor recovery units can be used to recover gas which can then be sold as an 

input to industrial processes or to other end users, such as CNG and LNG for vehicles. 

Finally, as we discussed above, casinghead gas can be an important source of emissions 

and available control technologies include installing a low horsepower compressor to maintain 

low casinghead pressure.11

 

11 Larry S. Richards, Casinghead Pressure Reduction Methane Capture Technologies (2013), available at 

http://epa.gov/gasstar/documents/workshops/denver-2014/Casinghead_Pressure_Reduction.pdf