# 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. E XECUTIVE 

### S UMMARY

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

and VOC emissions. Emissions from both hydraulically fractured oil we ll completions and associated gas venting are significant and, abs ent controls, likely to increase in the future as swift development is projected to occur i n oil-rich formations.

o Completion emissions factor . The best available data suggest that uncontrolled oil well completion emissions range from 7.7 to 213 ton s CH 4 per event, substantially higher than the EPA inventory estimate of 0.0156 to ns CH 4 per event. Using

conversion factors based on data from the UT Produc tion 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 produ ction values to estimate uncontrolled completion emissions.

o National oil well completion emissions . National emissions estimates are significant, ranging from 44,000 – 272,000 tons CH 4 . The lower values, however, assume only horizontal wells are hydraulically frac tured 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 flar ing 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 Tex as basins and 75% of flaring

emissions are from the Williston basin.

• Control technologies are available that can cost-ef fectively 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 Redu ced 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 ass ociated with reducing emissions.

o Access to infrastructure. Infrastructure to support gas capture is swiftly ex panding in many oil producing areas, which can support capt ure of both completion emissions and associated gas. Emissions can also be reduced using alternativesE NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

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



### II. Q UANTIFYING THE 

### P ROBLEM OF 

### M ETHANE 

### & VOC L EAKS FROM 

### O IL


### W ELL 

### C OMPLETIONS AND 

### A SSOCIATED 

### G AS 

### P RODUCTION 

### (Q UESTIONS 

### 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, f or associated gas venting, the Oil Well Paper describes potential methodologies to derive per-wel l emissions and provides some data on

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

Per-event emissions factors are critical to underst and the effectiveness of mitigation technologies and evaluate costs associated with those technologi es. 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 impa ct 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 di scusses EPA’s evaluation of associated gas

emissions and Part II.C concludes.

We conclude:

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

from 7.7 to 213 tons CH 4 per event, substantially higher than the EPA inven tory estimate

of 0.0156 tons CH 4 per event. Using conversion factors based on data from the UT Production Study, VOC emissions from oil well compl etions likely range from 3.7 to 101.8 tons — higher than VOC emissions from gas wel l 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 CH 4 , 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 m ethane 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 basin s and 75% of flaring emissions are

from the Williston basin.E NVIRONMENTAL D EFENSE F UND • J UNE 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 substantia l increase in completion emissions. 1



### A. Hydraulically Fractured Oil Well Completions Emissi ons

Below, we briefly address the definition of “oil we lls.” We then analyze the different
emissions factors EPA presents, present an alternat ive methodology for estimating emissions
using Greenhouse Gas Reporting Program Subpart W, a nd finally discuss national emissions
from this source category.

1. Defining oil wells

A clear definition of oil wells is helpful for unde rstanding oil well emissions, though, as
we discuss in Part III, below, not necessary for ev aluating control technology (which are equally
applicable to oil and gas well emissions). The Oi l Well Paper points to several definitions of oil
wells, including NSPS OOOO and Subpart W. In parti cular, 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 distin guish 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 b ased on state regulatory definitions and thus
vary from state to state. The average GOR of gas we lls based on the first year production was
5,270,044 scf/bbl, compared to 3,840 scf/bbl for oi l wells. The percentage of wells with GOR
greater than 12,500 scf/bbl (the threshold identifi ed in the Oil Wells Paper) was 89.3% for gas

wells and 4.7% for oil wells.

Although we are not specifically advocating for def ining oil wells based on a GOR less
than 12,500 scf/bbl, we do recommend EPA clarify th at hydraulically oil wells that co-producing
natural gas also be required to reduce emissions, s imilar to the approach Colorado takes which
does not distinguish between oil and natural gas we ll completions. Ultimately, we emphasize
that defining “oil wells” helps to understand natio nal emissions from this source category, but it
is not critical for determining that pollution cont rol technology can effectively mitigate these

emissions.

1 EIA, Drilling often results in both oil and natura l gas production (Oct. 2013), available at http://www.eia.gov/todayinenergy/detail.cfm?id=1357 1.E NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

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

The Oil Wells Paper includes emission estimates bas ed on two types of data – direct measurements and production data. The average uncon trolled 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 lar ge, they are all much higher than the oil well completion emission factor of 0.0156 tons per compl etion currently used in the GHG Inventory.

The UT Study (Allen et al., 2013) includes direct m easurements 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, w hich 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 e missions were 3.2 tons, indicating 98.5% control efficiency.

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

uncontrolled emissions and initial production. In particular, the well operat ors reported the average daily gas production for the 30 days follow ing the completion, which can be compared to potential completion emissions. For the six hydr aulically fractured oil wells, potential completion emissions ranged from 2.0 to 20.1 days o f average daily gas production with an overall average of 5.0 days (assuming a gas composi tion of 78.8% methane). The average completion duration of these wells was 3.3 days, wh ich indicates that completion flowback emission rates can exceed the average rate of produ ction 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 o n analyses of gas production data and assumptions about the relationship between producti on data and completion emissions. Though similar, individual results varied based on assumpt ions 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 da ta it uses. In particular, EC/R calculated average daily production based on first-year’s prod uction. Gas production typically declines over time – an EDF analysis of DI Desktop production dat a from 15,962 oil wells with first production in 2012 determined that average daily pr oduction during the first year is 72% of practical initial production (DI Desktop bases prac tical initial production on the 2 nd 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 ave rage production rate; therefore, use of the lower average daily production during the first yea r 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 f lowback emission rates over time – the 27
completion flowbacks emission rates are highly dyna mic and variable, which demonstrates the
assumption of constant or linearly increasing emiss ions is rarely true. However, the critical
parameter for estimating emissions is the equivalen t days of production, not the change ofE NVIRONMENTAL D EFENSE F UND • J UNE 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 prod uction, higher than the equivalent days used in
all the analyses except the EC/R analysis, which us ed 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 substantiall y underestimates emissions).

Although the UT Study data is limited for hydraulic ally fractured oil wells, the relationship it helps to establish between initial production and completion emissions can be used to estimate uncontrolled emissions. Assuming poten tial emissions are equivalent to 5 of days of initial first 30 day production and that produced f lowback gas is 78.8% methane, the average potential completion emissions of the 15,962 oil we lls 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 hyd raulically fractured gas wells that vent (45.2 tons/completion) than the oil well completions (0.0 156 tons/completion).

Finally, we note that oil wells typically have a gr eater percentage of VOCs than gas wells, a relationship that the data from the UT stu dy helps to substantiate. Using a conversion factor of 0.478 lbs VOC / lbs CH4, based on gas com position data from 18 sites in the UT Production Study with a GOR less than 12,500 scf/bb l, 2 VOC emissions from oil well completions likely range from 3.7 to 101.8 tons — h igher than VOC emissions from gas well completions.

3. Other Methodologies for Estimating Oil Well Complet ion Emissions

(Question 3)

EPA’s Greenhouse Gas Reporting Program Subpart W fo r petroleum and natural gas systems requires reporting of emissions from gas we ll completions and workovers, but not oil well completions and workovers. Nonetheless, in 20 11 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 D I Desktop data to assess if these completions were actually oil wells. In approximately 75% of t he counties from which these completion reports came, over half of the wells with first pro duction in 2011 and 2012 were oil wells. This supports the conclusion that some operators have vo luntarily submitted emissions data from oil well completions and workovers.

For the 2014 US GHG Inventory, EPA used 2011 and 20 12 Subpart W data to develop emission factors for gas well completions and worko vers. 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-basi ns (Table 1). The average emission factor for all oil formation completions and workovers is 6.2 metric tons CH 4 per event, or more than 400 times higher than the current oil well completi on emission factor. EDF also developed

2 David T. Allen et al., Measurements of methane emi ssions at natural gas production sites in the Unite d States, PNAS Early Edition (2013)[hereinafter “UT Study”], available at http://www.pnas.org/cgi/doi/10.1073/ pnas.1304880110.E NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

6 separate emission factors for each combination of e mission controls reported under Subpart W: uncontrolled (“vented”) completions, completions co ntrolled with a flare, completions controlled with a REC, and completions controlled with both fl ares and REC. The emission factors for the four categories range from 3.1 MT CH4 per completio n for completions with REC to 21.8 MT

CH 4 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 CH 4 /
event) Workovers

(Mg CH 4 /
event) Completions

&

Workovers
(Mg 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

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 effic iency 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 emissi on 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 v ent. In this section, we focus on evaluating activity factors and how they impact national estim ate, 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 use d to estimate the number of hydraulically fractured oil wells. D rillingInfo 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 hydraulic ally fractured. The EC/R analysis estimated the number of hydraulically fractured oil well completi ons 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 me thod 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 bot h controlled and uncontrolled completions.E NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

7 FracFocus, a chemical disclosure registry managed b y the Ground Water Protection Council and Interstate Oil and Gas Compact Commissi on, includes well production type of the reported hydraulically fractured wells. The FracFo cus website does not currently allow bulk data downloads, but the organization SkyTruth has compil ed 2011 and 2012 data for public use. The compiled FracFocus data includes records from 12,05 6 oil wells with hydraulic fracturing dates in 2012. Although reporting to FracFocus is mandat ory in several states, it is voluntary in others and therefore the actual number of completions is l ikely 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 d o 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 numbe r by filtering by formation type; therefore,

it is evident that this method underestimates oil w ell 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 oi l wells. The 2012 GHG Inventory uses an activity factor of 15,753 oil well completions base d on the Energy Information Administration Monthly Energy Review. Assuming both the EIA and F racFocus values are accurate, at least 76.5% of oil wells are hydraulically fractured. Thi s is similar to an 80% hydraulic fracturing rate for oil wells estimated by industry experts.

The Oil Wells Paper states that the EDF/Stratus ana lysis 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 unco ntrolled 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 compl etions. This activity factor may be conservatively high since it is based on the assump tion that all oil wells are hydraulically fractured (though we note the emissions factor we u se is lower than most). Using the FracFocus activity data of 12,056 completions, the estimate w ould be reduced to 189,279 metric tons (208,644 short tons).

Recompleted Oil Wells (Question 6). As indicated in the white paper, there is uncertain ty about the rate of recompletions of hydraulically-fr actured oil wells. A likely reason for the lack of data is the relatively young age of most unconve ntional oil wells. As the population of wells ages, the recompletion rate should increase. Contin uing 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 emissi ons by 98.5%, but the sample size is too

small to estimate the fraction of wells that curren tly use these controls. There is some information available from the Subpart W data of ga s well completions and workovers in oil formation sub-basins. As stated previously, we bel ieve much of the data are from voluntarily reported oil well completions. Using the same metho d as EPA to estimate the number ofE NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

8 uncontrolled (“vented”) completions, completions co ntrolled with a flare, completions controlled with a REC, and completions controlled with both fl ares and REC for the 2012 GHG Inventory,

we estimated the distribution of controls for the s ubset of completions from oil formation subbasins. The method was able to unambiguously class ify 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 u sing 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, a s we discuss above, these emissions are
likely to increase given the swift pace of developm ent in regions that co-produce oil and natural
gas. Over the last two years, rising oil prices an d 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 thr ough 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 f rom associated gas venting and flaring from onshore petroleum & natural gas systems for facilit ies 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 ventingE NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

9 wells and 6,901 flaring wells with 59,528 and 30,00 7 metric tons of methane emissions from venting and flaring, respectively, for a total of 8 9,535 metric tons (98,695 short tons).

There are large differences among basins in the num ber 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 diff erences between the average emissions of the two basins – the Permian Basin had 5,350 venting we lls with an average of 4.3 metric tons per well, while the East Texas Basin had 20 venting wel ls with an average of 734.4 metric tons per well. For flaring wells, the Williston Basin and G ulf 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 particu lar had high rates of flaring, contributing 75% of total emissions. Overall, the average methane e missions were 5.3 metric tons per venting well and 4.3 metric tons per flaring well.

The North Dakota Industrial Commission requires rep orting 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 emit ting 25,269 metric tons methane emissions, similar to the 23,922 metric tons reported to Subpa rt W. The close agreement is a favorable indication of the accuracy of the Subpart W estimat es, but the North Dakota reporting requirements may result in higher accuracy compared to other basins.

Additionally, uncertainty about flare control effic iency decreases the accuracy of the flaring methane emissions. Subpart W requires use o f the flare manufacturer’s reported combustion efficiency or 98% if unavailable. Emiss ions could be higher if equipment malfunctions decrease the control efficiency. Furth ermore, Subpart W estimates do not include emissions from facilities below the reporting thres hold 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 associ ated gas but urge the agency also to consider casinghead gas, which is also related to o il 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. U NDERSTANDING THE 

### L ANDSCAPE OF 

### M ITIGATION 

### T ECHNOLOGY 

### , E FFECTIVENESS 

### , AND 

### C OST 

### (Q UESTIONS 

### 7, 8, 9, 12, 13)

EPA’s White Papers similarly address mitigation tec hnologies applicable to both hydraulically fractured oil well completion emissio ns 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 P art III.A. In Part III.B, we address EPA’s analysis of alternative technologies capable of red ucing emissions from these sources. ForE NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

10 reference, we discuss the prevalence of these contr ol 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 St udy demonstrates that both Reduced Emission Completions (“RECs”) and flaring are feasi ble at hydraulically fractured oil wells. RECs are far preferable because they captur e gas that would otherwise be wasted, and accordingly, can significantly offset the costs associated with reducing emissions.

• Infrastructure to support gas capture is swiftly ex panding in many oil producing areas, which can support capture of both completion emissi ons and associated gas. Emissions can also be reduced using alternatives such as on-s ite power generation.

• Flaring is broadly available and cost-effective, bu t 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 EP A’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 Fr actured Oil Wells (Questions 7, 13)

As we describe above, the distinction between an oi l and gas well is artificial, and a completion operation at either can involve separati on of natural gas from liquid hydrocarbons and water. Completion flowbacks may contain differ ent percentages of oil, gas, and water, but this has little impact on the feasibility of techno logies capable of controlling emissions at these sources. As EPA’s White Paper notes, this conceptu al understanding is supported by data from the UT Production study, which definitively confirm s that RECs and flaring are feasible (and have been done) at hydraulically fractured oil well s. 4 Four of these wells controlled completion flowback emissions with flaring, and two of the wel ls utilized a combination of RECs and flaring.

In addition, the Oil Wells Paper requests comment o n 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 Appendi ces, 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 tha t they provide evidence that RECs and flaring

4 White Paper at YY.E NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

11 have been successfully performed at wells with thes e characteristics. Table 2, below,

summarizes these characteristics.

Table 2: Summary of Well Characteristics at Hydraul ically 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 cou rse of the completion. These values were measured during the period when completion emission s were sent to a control device or to sales.

• Access to Infrastructure . Access to infrastructure has no bearing on wheth er emissions can be controlled, but instead is importa nt to understanding how they can be controlled – through capture or flaring. In frastructure is also currently being built out in many regions co-producing gas an d oil, and in other gas fields infrastructure is not an issue. Moreover, data fro m an October 2013 report from the North Dakota Pipeline Commission showed that 55 % all flaring in the state occurred at wells connected to gathering infrastruc ture. 6

• Well Pressure. Well pressure likely has some bearing on whether f lowback emissions can be controlled – as EPA has recognized in the gas well context 7

– but several of the wells measured here controlled e missions despite having average well pressures lower than the 500 psig EPA highlights in its charge question. In addition, well pressure fluctuates ov er time during a completion and all but two of the completions (GC-2 and GC-7) cont rolled 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/ndp a-detailed-look-at-gas-gathering-2013.pdf.

7 EPA, Technical Support Document for NSPS Subpart OOOO (2012).E NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

12 • Methane Concentration . The data also show that methane concentration al so fluctuates over time. The table, above, presents a verage methane concentration data from the period during which gas was sent to s ales or flared, showing that gas streams with methane content as little as 35% w ere susceptible to flaring. Methane concentrations during initial flowback peri od 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 da taset between GOR and the feasibility of performing a REC or flaring. Pe rhaps 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 fla re. That was not the case, however, in the UT Study and the study does not con tain data to support that conclusion. GOR does, of course, impact the cost o f 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 feasi ble at gas wells and oil wells. This conclusion is reinforced by the fact that states li ke Colorado require reduced emissions completions for oil and gas wells, without distinct ion, and instead focus on pressure characteristics as the determinant of completion fe asibility. 9

2. Costs of RECs and Flaring at Hydraulically Fracture d 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 EP A’s White Paper presents are reasonable, and in some cases, conservative.

RECs . EPA’s White Paper presents lower-bound costs ass ociated 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 S tudy 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 c osts 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. Accor dingly, newer data may show that cots have declined for performing these operations.

These estimated costs will also be offset by cost r ecovery associated with gas capture. For the emissions factors presented from the UT stu dy, monetary savings resulting from gas recovery taking place over the duration of the comp letion average $25,630, assuming the recovered gas sells at $4/Mcf. As EPA recognizes i n 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).E NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

13 mitigation available would depend on the market pri ce of the gas and the percentage of gas recovered during a REC.

Flares . The White Paper also presents costs for completi on combustion devices or flares, citing an average cost figure for enclosed combusto rs of $18,092. In addition to the EPA has previously estimated the cost of flaring completion s emissions to be $3,523 per well. 10
Moreover, the ICF Report contains different cost as sumptions about performing high-efficiency flaring, which are substantially higher than all ot her estimates: initial capital cost of $50,000, with an additional $6,000 in fuel costs for ignitio n.

In all of these figures, annual costs are conservat ively assumed to be equal to the capital costs. The resulting costs therefore do not take in to account the fact that completion combustion devices are deployed to control emissions from a nu mber 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 conditi ons.

3. Emissions Reductions Associated with RECs and Flari ng 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 usi ng 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 technolog y or technique. EPA also noted that any gas not recovered can be routed to a completion combust ion device to achieve a minimum 95%

reduction in emissions.

The UT study found that “for those wells with metha ne capture or control, 99% of the potential emissions were captured or controlled,” a nd both of the wells that co-produced oil and gas and were controlled through a REC reported a gr eater than 98% reduction in methane emissions. Though we recognize that these factors can influence control effectiveness, it is likewise important to emphasize that equipment conf iguration 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 fl owback, (2) a separator that sent gas to sales or a flare, and (3) a flowback tank for hydrocarbon liqu ids that vented to a combustion device, helping to minimize venting during the initial stag es of the flowback operation.

For flaring, EPA estimated an average control effic iency of 95% over the duration of a completion or recompletion. This figure incorporate s assumptions, including that the combustion device has a continuous ignition source and an exte rnal fuel supply. Other factors, such as weather, will also affect the efficiency of complet ion combustion devices. The UT study, on the other hand, assumed 98% control efficiency. Both o f 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 Perf ormance for Crude Oil and Natural Gas Production, Transmission, and Distribution, Background Technica l Support Document for Proposed Standards (July 201 1),

available at http://www.epa.gov/airquality/oilandgas/pdfs/201107 28tsd.pdf.E NVIRONMENTAL D EFENSE F UND • J UNE 16, 2014

14 control the conditions (like weather) that might le ad 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 m ay be deployed in different contexts and have shown varying levels of effectiveness. Na tural gas may be used to produce electricity at or near a well using a gas turbine generator, wh ich 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 installi ng a low horsepower compressor to maintain low casinghead pressure. 11

11 Larry S. Richards, Casinghead Pressure Reduction M ethane Capture Technologies (2013), available at http://epa.gov/gasstar/documents/workshops/denver-2 014/Casinghead_Pressure_Reduction.pdf